emesz-10k_20181231.htm

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

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

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

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

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one)

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐ Yes ☐ No

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

As of June 30, 2018, the last business day of the registrant's second fiscal quarter of 2018, the aggregate market value of the registrant's common units held by non-affiliates of the registrant was $158,972,355 based on the closing price as reported on the New York Stock Exchange composite tape on that date.

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. Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, those summarized below:

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.

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.

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.

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.

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 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.

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. Emerge was formed prior to the closing of its IPO, when 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 Superior Silica Sands LLC (“SSS”) and Allied Energy Company LLC (“AEC”) to Emerge who conveyed its interest in SSS and AEC to its subsidiary Emerge Energy Services Operating LLC (“Emerge Operating”).

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 Fuel Business Purchase Agreement will be released to Emerge, provided that no unsatisfied indemnity claims exist at such time. See Note 5 to our Consolidated Financial Statements for further discussion.

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.

We are a publicly-traded limited partnership formed in 2012 by management and affiliates of Insight Equity. 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.

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.

On April 18, 2019, we entered into a Restructuring Support Agreement pursuant to which we have agreed to the principal terms of a proposed financial restructuring of the Partnership. Please see “Item 1A. Risk Factors” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources.”

On July 15, 2019, Emerge, Emerge Energy Services GP LLC, Emerge Operating, SSS and Emerge Energy Services Finance Corporation (collectively, the “Debtors”), filed voluntary petitions for relief (collectively the “Petitions” and, the cases commenced thereby, the “Chapter 11 Cases”) under chapter 11 of title 11 of the United States Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the District of Delaware (the “Bankruptcy Court”). The Chapter 11 Cases are jointly administered under the caption “In re: Emerge Energy Services LP, et al.” The Debtors will continue to operate their business as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. The Chapter 11 Cases were filed in order to effect the Debtors’ joint plan of reorganization (as amended from time to time, the “Plan”).

11 of the Bankruptcy Code (as may be amended from time to time, the “Disclosure Statement”). The Disclosure Statement Order also approved the Company’s solicitation procedures with respect to the Plan. Pursuant to the terms of the Plan, only (a) holders of claims arising from, under or in connection with the certain Note Purchase Agreement (the “Prepetition Notes Agreement”) by and among the Partnership, certain of the Partnership’s subsidiaries, HPS, in its capacity as administrative notes agent and collateral agent, and certain noteholders party thereto (such claims, the “Class 5 Prepetition Notes Claims”) and (b) holders of general unsecured claims (such claims, the “Class 6 General Unsecured Claims”) are entitled to vote to accept or reject the Plan. The Company commenced solicitation for the Plan on September 13, 2019 by distributing, among other things, the Plan, the Disclosure Statement, and ballots to vote to accept or reject the Plan to holders of Class 5 Prepetition Notes Claims and Class 6 General Unsecured Claims.

As further provided in the Plan and pursuant to the terms of the Plan, if and only if at least two-thirds (2/3) in dollar amount and more than one-half (1/2) in number of Class 6 General Unsecured Claims vote to accept the Plan, then each holder of equity interests in the Partnership (the “Class 9 Old Emerge LP Equity Interests”) shall receive, in full satisfaction, settlement, discharge and release of, and in exchange for, such allowed Class 9 Old Emerge LP Equity Interests, its pro rata share of new warrants contemplated under that certain new warrants agreement (the “New Warrants Agreement”)¹ representing five percent (5%) of new limited partnership interests in the Partnership, as reorganized pursuant to the Plan (the “New Limited Partnership Interests”), issued and outstanding on the effective date of the Plan, prior to dilution by equity issued in connection with the new management incentive plan. As further provided in the Plan and pursuant to the terms of the Plan, if less than two-thirds (2/3) in dollar amount or fewer than one-half (1/2) in number of Class 6 General Unsecured Claims vote to accept the Plan, Class 6 will have rejected the Plan, in which case the holders of Class 9 Old Emerge LP Equity Interests shall not receive any distribution or retain any property on account of such equity interests in the Partnership and such equity interests in the Partnership will be cancelled without further notice.

In addition, and as further provided in the Plan and pursuant to the terms of the Plan, if and only if at least two-thirds (2/3) in dollar amount and more than one-half (1/2) in number of Class 6 General Unsecured Claims vote to accept the Plan, then (a) each holder of an allowed Class 5 Prepetition Notes Claim shall receive in full satisfaction, settlement, discharge and release of, and in exchange for, such claim, its pro rata share of: (1) secured notes contemplated under that certain new second lien notes agreement (the “New Second Lien Notes”), if any; (2) ownership interests (“New Emerge GP Equity Interests”) in the new general partner of the Partnership, as reorganized pursuant to the Plan; (3) preferred interests (the “Preferred Interests”) in the Partnership, as reorganized pursuant to the Plan less any Preferred Interests issued to satisfy claims in connection with the DIP Facility (as defined below); and (4) ninety-five percent (95%) of the New Limited Partnership Interests issued and outstanding on the effective date of the Plan, prior to dilution by equity issued in connection with the new management incentive plan and any issuances pursuant to the New Warrants Agreement; and (b) each holder of an allowed Class 6 General Unsecured Claim shall receive, in full satisfaction, settlement, discharge and release of, and in exchange for, such allowed Class 6 General Unsecured Claim: its pro rata share of: (1) five percent (5%) of the New Limited Partnership Interests issued and outstanding on the effective date prior to dilution by the new management incentive plan and any issuances pursuant to the New Warrants Agreement; and (2) new warrants contemplated under the New Warrants Agreement representing ten percent (10%) of the New Limited Partnership Interests issued and outstanding on the effective date prior to dilution by the new management incentive plan. As further provided in the Plan and pursuant to the terms of the Plan, if less than two-thirds (2/3) in dollar amount or fewer than one-half (1/2) in number of Class 6 General Unsecured Claims vote to accept the Plan, Class 6 will have rejected the Plan in which case (a) each holder of an allowed Class 5 Prepetition Notes Claims shall receive, in full satisfaction, settlement, discharge and release of, and in exchange for, such claim, its pro rata share of: (1) the New Second Lien Notes, if any; (2) the New Emerge GP Equity Interests; (3) the Preferred Interests less any Preferred Interests issued to satisfy claims in connection with the DIP Facility; and (4) one hundred percent (100%) of the New Limited Partnership Interests issued and outstanding on the Effective Date prior to dilution by equity issued in connection with the new management incentive plan; and (b) Class 6 General Unsecured Claims will be discharged without further notice and each holder of a Class 6 General Unsecured Claim shall not receive any distribution or retain any property on account of such Class 6 General Unsecured Claim.

In addition, subject to certain exceptions, under the Bankruptcy Code, the Debtors may assume, assign, or reject certain executory contracts and unexpired leases subject to the approval of the Bankruptcy Court and certain other conditions. Generally, the rejection of an executory contract or unexpired lease is treated as a pre-petition breach of such executory contract or unexpired lease and, subject

to certain exceptions, relieves the Debtors of performing their future obligations under such executory contract or unexpired lease but entitles the contract counterparty or lessor to a pre-petition general unsecured claim for damages caused by such deemed breach. Counterparties to such rejected contracts or leases may assert claims against the applicable Debtor's estate for such damages. Generally, the assumption of an executory contract or unexpired lease requires the Debtors to cure existing monetary defaults under such executory contract or unexpired lease and provide adequate assurance of future performance. Accordingly, any description of an executory contract or unexpired lease with the Debtors in this Annual Report, including where applicable a quantification of our obligations under any such executory contract or unexpired lease with the Debtors is qualified by any overriding rejection rights we have under the Bankruptcy Code. Further, nothing herein is or shall be deemed an admission with respect to any claim amounts or calculations arising from the rejection of any executory contract or unexpired lease and the Debtors expressly preserve all of their rights with respect thereto.

In connection with the Chapter 11 Cases, on July 17, 2019, the Debtors received interim authorization from the Bankruptcy Court to enter into the DIP Facility (as defined below) and on August 14, 2019 the Debtors received final authorization from the Bankruptcy Court to enter into the DIP Facility. In connection with the Chapter 11 Cases, on August 14, 2019, the Debtors also received authorization from the Bankruptcy Court to reject certain executory contracts and unexpired leases, including but not limited to the Debtors’ rail car lease agreements, nunc pro tunc to July 15, 2019, and to enter into certain new rail car lease agreements nunc pro tunc to July 15, 2019.

Parties may obtain a copy of the Disclosure Statement and the Plan by: (a) calling the Company’s voting and claims agent, Kurtzman Carson Consultants LLC, at 877-634-7165 (toll-free in US and Canada) or 424-236-7221 (for international callers); (b) writing to Emerge Energy Services, c/o Kurtzman Carson Consultants LLC, 222 N. Pacific Coast Highway, Suite 300, El Segundo, CA 90245; and/or (c) visiting the Debtors’ restructuring website at: http://www.kccllc.net/emergeenergy. Parties may also obtain any documents filed in the Chapter 11 Cases for a fee via PACER at http://www.deb.uscourts.gov

In connection with the Chapter 11 Cases, on July 19, 2019 (the “DIP Closing Date”), the Debtors entered into a senior secured priming and superpriority debtor-in-possession credit and security agreement (the “DIP Facility”) with HPS Investment Partners, LLC, as administrative agent and collateral agent (the “DIP Administrative Agent”) and the financial institutions from time to time party thereto.

The DIP Facility contains various covenants and restrictive provisions which also require the maintenance of certain financial and other related covenants such as the following:

In addition, the DIP Facility contains various milestone requirements related to the Chapter 11 case along with disclosure requirements which include, but not limited to:

The Debtors have exceeded the Permitted Variance with respect to net cash flow for the week of August 26, 2019 and September 2, 2019 and the bi-weekly period ending August 30, 2019 and have breached milestone requirements in the DIP Facility related to the filing of the Annual Report and the Quarterly Report for the quarter ended March 31, 2019, both constituting events of default that allow for the lenders to exercise rights and remedies, including but not limited to declaring outstanding principal, fees and interest thereunder immediately due and payable. In addition, due to these events of default, the lenders are charging default interest equal to an additional 2% on all obligations thereunder. The DIP Facility permits advances during an event of default, in the DIP Administrative Agent’s sole discretion. Additionally, we did not meet the milestone requirement for filing the Quarterly Report for the quarter ended June 30, 2019, which would also constitute an event of default under the DIP Facility.

Proceeds of the DIP Facility can be used by the Debtors for, among other things, the Debtors’ general business purposes, including working capital requirements during the pendency of the Chapter 11 Cases and to pay certain fees and expenses of professionals retained by the Debtors, in each case subject to certain limitations provided in the DIP Facility. Further information on the terms of the DIP Facility is included below under “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations–Liquidity and Capital Resources–DIP Facility.”

On May 11, 2018, we signed a 25-year lease deal for the mining rights to approximately 600 acres located in Kingfisher County, Oklahoma, about 60 miles northwest of Oklahoma City. We purchased 40 acres of land adjoining the leased acreage on which to construct wet and dry processing plants expected to have a capacity of 1.5 million tons per year. This facility will serve the Mid-Continent region. Construction of the wet and dry processing plants is temporarily suspended due to cash flow restrictions from our lenders. We are working with our lenders and hope to move ahead with this project.

On April 12, 2017, we acquired 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. 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 constructed new wet and dry plants on the site. The new dry plant commenced operations in late April 2018. Full construction of the dry and wet plant was completed in January 2019.

On June 21, 2019, a levee breach incident occurred at our San Antonio facility. A section of the wall in the facility’s mud retention pond failed causing an inundation of water and sediment to the mine. No injuries occurred as a result of the breach and representatives from MSHA were given notice of the incident. MSHA issued a Section 103(k) order on the entire mine area, meaning we could not access any part of the impacted mine. During the order, the primary production lines at the mine and wet processing plant remained idle, but we restarted a small wet processing line not impacted by the Section 103(k) order. We are also purchasing higher-cost third party wet feed to supplement our own internal feed.

In spite of the primary mining and wet plant operations in San Antonio having been shut down since June 21, 2019 as a result of the incident described above, we are able to continue operating our dry plant and delivering product to customers. On September 16, 2019, we were notified that the Section 103(k) order has been lifted. We expect that the facility will be fully operational in the near term. We are assessing our claims under insurance coverage.

On October 11, 2019, one of the dryer exhaust stacks on the facility’s dry plant collapsed in a high wind event. The Company immediately ceased operations at the dry plant in order to protect the work force, assess the damages, and determine necessary repairs. If the dry facility is non-operable for a significant period of time, it could have a material adverse effect on our financial position, liquidity or results of operations.

On May 11, 2018, we signed a 25-year lease for the mining rights to approximately 600 acres located in Kingfisher County, Oklahoma, about 60 miles northwest of Oklahoma City. We purchased 40 acres of land adjoining the leased acreage on which to construct wet and dry processing plants expected to have a capacity of 1.5 million tons per year. The site contains American Petroleum Institute (“API”) specification, strategic reserves (40/140 mesh sands), which will serve the Mid-

Continent region. Construction of the wet and dry processing plants is temporarily suspended due to cash flow restrictions from our lenders. We are working with our lenders and hope to move ahead with this project.

On April 12, 2017, we acquired our San Antonio operations. 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 constructed new wet and dry plants on the site. The new dry plant commenced operations in late April 2018. Full construction of the dry and wet plants was completed in January 2019. Our San Antonio reserves contain API specification, strategic reserves (40/70 and 100 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 San Antonio plant to the Eagle Ford Shale, we sell all of the frac sand produced at the San Antonio plant into the Eagle Ford Shale, which is currently the second most active in the United States.

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

We mine, process and distribute high quality silica sand, a key input for the hydraulic fracturing of oil and gas wells. Our San Antonio facility consists of a dry plant with a permitted capacity of 4.0 million finished tons per year. Our sand reserves in San Antonio supply the wet plant and the dry plant with local Texas sand. We also have a 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. 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. As of December 31, 2018, we also had 13 transload facilities located throughout North America in the key basins where we deliver our sand, as well as a fleet of 5,186 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 and 2018. The market for frac sand began to soften in early August 2018, due to a decline in well completion activities as well as oil and natural gas exploration and production companies’ budget exhaustions. These factors, along with the new production from in-basin frac sand competitors discussed below, led the sand market to quickly turn from a state of short supply in the first half of the year to oversupply in the second half of 2018 and into 2019. As a result, the entire industry has experienced pricing pressure, particularly on the northern white product. We believe that the premium geologic characteristics of our Wisconsin sand reserves, the strategic location of our in-basin sand mines, our location on multiple Class 1 rail lines, our 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. At certain sites, 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. We introduced dredging mining techniques to our Kosse mine in 2018, whereby sand deposits are extracted from the ground with water. The resulting slurry is transported via pipeline to the wet processing facility. 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 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 mine, wet plant and dry plants in San Antonio, Texas operate year-round. We currently operate our facilities with crews of 18 employees who work twelve-hour shifts and average 42 hours a week. As part of our expansion strategy in San Antonio, we constructed an additional plant on the site which was operational in January 2019. Our San Antonio reserves contain API-specification, strategic reserves (40/70 and 100 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 San Antonio plant to the Eagle Ford basin, we sell all the frac sand produced at the San Antonio plant into the Eagle Ford basin, 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 API-specific 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.

Our frac sand facilities are located in Barron County and Chippewa County, Wisconsin, and San Antonio and Kosse, Texas. Based on the reports of third-party independent engineering firms, we have 155.2 million tons of proven recoverable reserves. We are currently capable of producing up to 13.5 million tons and 10.9 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 May 11, 2018, we signed a 25-year lease for the mining rights to approximately 600 acres located in Kingfisher County, Oklahoma, about 60 miles northwest of Oklahoma City. We purchased 40 acres of land adjoining the leased acreage on which to construct wet and dry processing plants expected to have a capacity of 1.5 million tons per year. This facility will serve the Mid-Continent region. Construction of the wet and dry processing plants is temporarily suspended due to cash flow restrictions from our lenders. We are working with our lenders and hope to move ahead with this project.

Each of our facilities undergoes regular maintenance to minimize unscheduled downtime and to ensure that the quality of our frac sand meets applicable International Organization for Standardization (“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, 2018.

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 San Antonio and Kosse, Texas 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 and offers a lower landed cost to the wellsite given the mines’ proximity to active drilling regions.

Our reserves are categorized as proven or probable recoverable in accordance with and subject to the definitions in SEC Industry Guide 7, and our third-party geologists and mining engineers apply those definitions to estimate the sand reserves that could be extracted at a cost that is economically and legally feasible. As of December 31, 2018, we had a total of 155.2 million tons of estimated proven recoverable mineral reserves. The quantity and nature of the mineral reserves at each of our properties are estimated 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 and San Antonio facilities, each as of December 31, 2018. Our Oklahoma proven reserve estimates were prepared by Westward Environmental, Inc. in September 2018.

Our third-party geologists and engineers annually update our estimates of sand reserves that are economically and legally feasible to extract, making necessary adjustments for operations at each location during the year, additions or reductions due to property acquisitions and dispositions, quality adjustments and mine plan updates. The third-party geologists and engineers apply a number of factors in making such adjustments, including analysis of our current mining methods and processing techniques and physical inspection of mine characteristics and accessibility.

The SEC recently adopted Final Rule 13-10570, Modernization of Property Disclosures for Mining Registrants, which will replace the mining property disclosure requirements of Industry Guide 7. We will be required to comply with the new rules starting with the fiscal year beginning January 1, 2021, at which point Industry Guide 7 will be rescinded. In connection with the pending updates to mining property disclosure requirements, reserves estimates disclosed in our future Annual Reports will include an analysis of operating costs, capital costs and long-term anticipated sales volume and price in evaluating the economic viability of our reserves.

Our mineral reserve leases in Wisconsin with third-party landowners expire at various times between 2036 and 2038. Our mineral reserve lease in Kingfisher, Oklahoma expires in 2043. 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.

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.

Our Kosse plant mines sands from the Simsboro deposits consisting of mostly sand units, including some mudstones, silts and clays. In addition to frac sand, Kosse also produces industrial sands for foundry, construction, and masonry.

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. Due to the current northern white sand market conditions, we have idled our higher cost mines and plants in order to reduce our operating costs and conserve liquidity.

In April 2017, we acquired the mineral rights to a 634 acre mineral deposit located in San Antonio, Texas, adjacent to our San Antonio dry plant. 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, 2018, our San Antonio deposit contained 39.3 million tons of proven recoverable reserves and 18.1 million tons of probable frac sand reserves. San Antonio proven recoverable reserve estimates were adjusted in 2018 for the reduction of the coarser 30/40 material. Based on the current market demand, there is no longer a market for the coarser 30/40 in-basin material, and it is therefore considered waste. Thus, our 2018 reserve estimates were updated based on a revised average recovery factor for the site. As part of our expansion strategy in San Antonio, we constructed a wet plant on the site. Construction of this wet plant was completed in January 2019, and has a capacity to produce 4.5 million tons of wet sand per year. With the completion of our wet plant in San Antonio in 2019, we believe that our operations have a low cost structure when mining internal feed.

We own the mineral rights to a 225 acre mineral deposit located in Kosse, Texas, adjacent to our Kosse dry plant. As of December 31, 2018, the Kosse mineral deposit contained 21.5 million tons of proven recoverable reserves which we process into a high-quality, 100 mesh frac sand. Kosse proven recoverable reserve estimates were adjusted in 2018 for the reduction of the coarser 20/40 material. Based on the current market demand, there is no longer a market for in-basin 20/40 material, and it is therefore considered waste. Thus, our 2018 reserve estimates were updated based on a revised average recovery factor for the site. Also, as a result of introducing dredging mining techniques in 2018, we can mine material that was previously considered overburden, thus resulting in an addition to the total reserve in 2018. 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.

Our Auburn wet plant can process up to 2.0 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 240 acres adjacent to our

New Auburn wet plant. The site contains 15.5 million tons of proven recoverable sand reserves. Due to the current northern white market conditions, we do not plan to reopen this mine in 2019.

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 80 acres. The site contains 5.3 million tons of proven recoverable sand reserves. The 2018 reserves were updated due to a revision in the mine plan and property line setbacks. Due to the current northern white sand market conditions, we do not plan to reopen this mine in 2019.

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 8.8 million tons of proven recoverable sand reserves. We started seasonal production in May 2019 but ran the plant for a shortened mining season in 2019 due to the current northern white sand market conditions.

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 3.3 million tons of proven recoverable sand reserves. We use hydraulic mining method at this site. Due to the current northern white sand market conditions, we do not plan to reopen this mine in 2019.

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 36.8 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. We use hydraulic mining method at this site. We started seasonal production in June 2019 but ran the plant for a shortened mining season in 2019 due to current northern white sand market conditions.

On May 11, 2018, we signed a 25-year lease for the mining rights to approximately 535 acres located in Kingfisher County, Oklahoma, about 60 miles northwest of Oklahoma City. This site contains 24.7 million tons of proven reserves. Construction of the wet plant is temporarily suspended due to cash flow restrictions from our lenders. We are working with our lenders and hope to move ahead with this project.

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. As part of our expansion strategy, we constructed an additional plant on the site. This additional plant was operational in the second quarter of 2018 and is capable of producing 4.0 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 sell all of the frac sand produced at the plant into this shale play, which is currently the second most active basin 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 have access to BNSF mainline which is 15 miles away. We will continue to sell sand to non-energy markets including construction, foundry and sports sands.

For the year ended December 31, 2018, our San Antonio facility produced 638,000 tons of frac sand.

In spite of the primary mining and wet plant operations in San Antonio having been shut down since June 21, 2019 as a result of the incident described in the “Mines and Wet Plant” section above, we restarted a small wet processing line not impacted by the Section 103(k) order. We are also purchasing higher-cost third party wet feed to supplement our own internal feed. On September 16, 2019, we were notified that the Section 103(k) order has been lifted. We expect that the facility will be fully operational in the near term. We are assessing our claims under insurance coverage.

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 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, 2018, our Kosse facility produced 383,000 tons of frac sand.

Our Arland dry plant is located on 22 acres that we own in the township of Arland in Barron County, Wisconsin. 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 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, 2018, our Arland facility produced 1.1 million tons of northern white frac sand. In November 2018, we idled our Arland plant due to the challenging market conditions.

Our Barron dry plant is located on 83 acres that we own in the township of Clinton, Wisconsin in Barron County. 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 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 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™) production circuits. In late 2015, we installed equipment that applies coating material for our SandGuard™ product.

For the year ended December 31, 2018, our Barron facility produced 1.6 million tons of northern white sand.

Our New Auburn dry plant is located in Barron County, Wisconsin, 12 miles from our 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.

For the year ended December 31, 2018, our New Auburn facility produced 1.0 million tons of northern white sand. In May 2019, we idled our New Auburn plant but are currently operating the facility for limited production runs. We also use the facility as a transload location to load dry sand from the Barron facility to the UP rail line.

On May 11, 2018, we signed a 25-year lease for the mining rights to approximately 600 acres located in Kingfisher County, Oklahoma, about 60 miles northwest of Oklahoma City. We purchased 40 acres of land adjoining the leased acreage on which to construct wet and dry processing plants expected to have a capacity of 1.5 million tons per year. This facility will serve the Mid-Continent region. Construction of the wet and dry processing plants is temporarily suspended due to cash flow restrictions from our lenders. We are working with our lenders and hope to move ahead with this project.

We sell our sand both free-on-board (“FOB”) at our plants as well as at transload facilities that are closer to the wellhead. For the year ended December 31, 2018, we sold 72% of our sand FOB plant and 28% FOB transload. 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. 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. As of December 31, 2018, we had a total of 5,186 railcars in our fleet, including 46 dedicated customer cars and 5,140 railcars under lease with a weighted average remaining term of 3.55 years. As of December 31, 2018, we conducted business through 13 transload facilities in North America, of which six were under long term contracts. These facilities are positioned to serve a number of our target markets. However, with the market shift from northern white sand and terminal sales, we are having issues covering our fixed costs for railcars and transload facilities. As part of our bankruptcy process, we rejected all railcar and select transload leases where we were paying above market rates or did not need access to the asset. Additionally, we entered into new railcar leases on amended terms with three select railcar lessors. We expect a significant reduction in the annual fixed costs from the rejection and where applicable re-negotiation of these leases.

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, 2018.

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 effect on our ability to continue operations at the affected facility. Expansion of our existing operations also is predicated upon securing the necessary environmental 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.

Our intellectual property consists primarily of patents, trade secrets, know-how and products such as “SandGuard™”. 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. In early 2016, we launched our self-suspending sand marketed under the brand SandMaxX™. This new technology offered the potential to increase production in oil and gas wells in addition to improving pump time and reducing other upfront costs. Trial wells proved that the technology is effective down-hole, but the customer adoption rate was slower than initially anticipated. Under the contract, we had the option to continue ownership of this technology after the initial installment period (which expired on May 25, 2018) by payment of significant additional funds. Given the lack of market acceptance for SandMaxX™ proppant, even after considerable efforts to market the product, we elected to discontinue ownership of the intellectual property after the initial installment period. Thus, we released all patents related to this technology in 2018.

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 94% of our total sales in 2018; non-frac sand sales, which consists of sales to customers in the sport sands, construction, and foundry industries, accounted for 6% of our total sales in 2018.

In 2018, total sales to customers under long-term contracts, including take-or-pay, fixed-volume, and efforts-based contracts, accounted for 60% of our total sales. As of December 31, 2018, we had 4.2 million tons under long-term contract with a weighted average remaining term of 2.1 years.

For the years ended December 31, 2018 and 2017, our top two customers, Liberty Oilfield Services and EP Energy Corporation, collectively accounted for 38% and 35% of our total revenues from continuing operations, respectively. However, in March 2019 we sued EP Energy Corporation for failure to purchase minimum contract volumes under a sand supply agreement with us. As a result, we no longer sell product to EP Energy Corporation. As of December 31, 2018, we have fully reserved our exposure and do not expect to have exposure on a go forward basis.

Our major vendors are rail providers, railcar lessors, mine operators, transloads, utilities providers and truckers. 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. We can experience periods of temporary service disruptions from our rail partners due to weather or their rail network issues. We have strong relationships with these rail providers, and we work closely with the railroads to minimize service disruptions when they occur.

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, and we expect competition to increase in the future as new entrants began 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 top producers of frac sand in 2018 by production capacity and sales volumes, together with U.S. Silica Holdings, Inc., Hi-Crush Proppants LLC, and Covia Holdings Corporation. 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.

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.

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.

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.

Mining and Workplace Safety. Our sand mining operations are subject to mining safety regulation. 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.

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 was required by June 2018, except for engineering controls, which have a compliance date of June 2021.

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.

In August 2012, the EPA published final rules that established 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 its storage tank standards in August 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. In September 2018, the EPA issued proposed revisions to its methane regulations, which, if finalized, would reduce certain obligations thereunder. 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.

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 strengthened 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.

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 in September 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 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.

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.

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, 2018, our general partner employed 279 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.

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.

You should carefully consider each of the following risks and all of the other information contained in this Annual Report on Form 10-K in evaluating us and our common units. Some of these risks relate principally to our business and the industry in which we operate, while others related principally to tax matters, ownership of our common units and securities markets generally. If any of the following risks were actually to occur, our business, financial position or results of operations could be materially adversely affected. In that case, we might not be able to pay the minimum quarterly distribution on our common units or the trading price of our common units could decline.

We are subject to the risks and uncertainties associated with Chapter 11 proceedings.

As a consequence of our filing for relief under Chapter 11 of the Bankruptcy Code, our operations and our ability to develop and execute our business plan, and our continuation as a going concern, will be subject to the risks and uncertainties associated with bankruptcy. These risks include the following:

As of December 31, 2018, we had total indebtedness (including unsecured indebtedness) of approximately $338 million. Our Note Purchase Agreement mature on January 5, 2023, and the majority of our other outstanding indebtedness will mature within the next four years. While we anticipate substantially all of our indebtedness will be exchanged for new equity ownership through the Plan, there is no assurance that the effectiveness of the Plan will occur in November, 2019 as expected, or at all.

These risks and uncertainties could affect our business and operations in various ways. For example, negative events associated with our Chapter 11 proceedings could adversely affect our relationships with our suppliers, service providers, customers, employees and other third parties, which in turn could adversely affect our operations and financial condition. Also, we need the prior approval of the Bankruptcy Court for transactions outside the ordinary course of business, which may limit our ability to respond timely to certain events or take advantage of certain opportunities. Because of the risks and uncertainties associated with our Chapter 11 proceedings, we cannot accurately predict or quantify the ultimate impact of events that occur during our Chapter 11 proceedings that may be inconsistent with our plans.

Even if a Chapter 11 plan of reorganization is consummated, we may not be able to achieve our stated goals and continue as a going concern.

Even if the Plan or any other Chapter 11 plan of reorganization is consummated, we will continue to face a number of risks, including further deterioration in commodity prices or other changes in economic conditions, changes in our industry, changes in demand for oil and gas and increasing expenses. Accordingly, we cannot guarantee that the Plan or any other Chapter 11 plan of reorganization will achieve our stated goals.

Furthermore, even if our debts are reduced or discharged through the Plan, we may need to raise additional funds through public or private debt or equity financing or other various means to fund our business after the completion of our Chapter 11 proceedings. Our access to additional financing is, and for the foreseeable future will likely continue to be, extremely limited, if it is available at all. Therefore, adequate funds may not be available when needed or may not be available on favorable terms, if they are available at all.

The RSA is subject to significant conditions and milestones that may be beyond our control and may be difficult for us to satisfy. If the RSA is terminated, our ability to consummate a restructuring of debt could be materially and adversely affected.

The RSA sets forth certain conditions we must satisfy, including timely satisfaction of conditions and milestones to consummate the restructuring. Our ability to timely satisfy such conditions and milestones is subject to risks and uncertainties that, in certain instances, are beyond our control. The RSA gives the Consenting Creditors the ability to terminate the RSA under certain circumstances, including the failure of certain conditions or milestones to be satisfied. Should the RSA be terminated, all obligations of the parties to the RSA will terminate (except as expressly provided in the RSA). A termination of the RSA may result in the loss of support for a restructuring and our ability to effect a restructuring in the future could be material and adversely affected.

Upon emergence from bankruptcy, our historical financial information may not be indicative of our future financial performance.

Our capital structure will be altered under the Plan. Under fresh start reporting rules that may apply to use upon the effective date of the Plan (or any alternative plan of reorganization), our assets and liabilities would be adjusted to fair values and our accumulated deficit would be stated to zero. Accordingly, if fresh start reporting rules apply, our financial condition and results of operations following our emergence from Chapter 11 would not be comparable to the financial condition and results of operations reflected in our historical financial statements. Further, a plan of reorganization could materially change the amounts and classifications reported in our consolidated historical financial statements, which do not give effect to any adjustments to the carrying value of assets or amounts of liabilities that might be necessary as a consequence of confirmation of a plan of reorganization.

Delays in the Chapter 11 Cases may increase the risks of our being unable to reorganize our business and emerge from bankruptcy and increase our costs associated with the bankruptcy process.

The RSA contemplates the consummation of the Plan through an orderly prearranged plan of reorganization, but there can be no assurance that we will be able to consummate the Plan. A prolonged Chapter 11 proceeding could adversely affect our relationships with customers, suppliers and employees, among other parties, which in turn could adversely affect our business, competitive position, financial condition, liquidity and results of operations and our ability to continue as a going concern. A weakening of our financial condition, liquidity and results of operations could adversely affect our ability to implement the Plan (or any other plan of reorganization). If we are unable to consummate the Plan, we may be forced to liquidate our assets.

In addition, the occurrence of the effective date of the Plan is subject to certain conditions and requirements in addition to those described above that may not be satisfied.

While the Plan has been confirmed by the Bankruptcy Court, it may not become effective because it is subject to the satisfaction of certain conditions precedent (some of which are beyond our control). There can be no assurance that such conditions will be satisfied and, therefore, that the Plan will become effective and that the Debtors will emerge from the Chapter 11 Cases as contemplated by the Plan. If the effective date is delayed, the Debtors may not have sufficient cash available to operate their businesses. In that case, the Debtors may need new or additional post-petition financing, which may increase the cost of consummating the Plan. There is no assurance of the terms on which such financing may be available or if such financing will be available. If the transactions contemplated by the Plan are not completed, it may become necessary to amend the Plan. The terms of any such amendment are uncertain and could result in material additional expense and result in material delays to the Chapter 11 Cases.

In certain instances, a Chapter 11 case may be converted to a case under Chapter 7 of the Bankruptcy Code.

Upon a showing of cause, the Bankruptcy Court may convert our Chapter 11 Cases to a case under Chapter 7 of the Bankruptcy Code. In such event, a Chapter 7 trustee would be appointed or elected to liquidate our assets for distribution in accordance with the priorities established by the Bankruptcy Code. We believe that liquidation under Chapter 7 would result in significantly smaller distributions being made to our creditors than those provided for in the Plan because of (i) the likelihood that the assets would have to be sold or otherwise disposed of in a distressed fashion over a short period of time rather than in a controlled manner and as a going concern, (ii) additional administrative expenses involved in the appointment of a Chapter 7 trustee, and (iii) additional expenses and claims, some of which would be entitled to priority, that would be generated during the liquidation and from the rejection of leases and other executory contracts in connection with a cessation of operations.

We may be subject to claims that will not be discharged in the Chapter 11 Cases, which could have a material adverse effect on our financial condition and results of operations.

The Bankruptcy Court provides that the confirmation of a plan of reorganization discharges a debtor from substantially all debts arising prior to consummation of a plan of reorganization. With few exceptions, all claims that arose on or prior to July 15, 2019 (i) would be subject to compromise pursuant to treatment under the Plan and/or (ii) would be discharged in accordance with the Bankruptcy Code consistent with the terms of the Plan.

Any claims not ultimately discharged pursuant to the Plan could be asserted against the reorganized entities and may have an adverse effect on our financial condition and results of operations on a post-reorganization basis.

The pursuit of the RSA has consumed, and the Chapter 11 proceedings will continue to consume, a substantial portion of the time and attention of our management, which may have an adverse effect on our business and results of operations, and we may face increased levels of employee attrition.

Although the Plan is designed to minimize the length of our Chapter 11 proceedings, it is impossible to predict with certainty the amount of time that we may spend in bankruptcy. The Chapter 11 proceedings will involve additional expense and our management will be required to spend a significant amount of time and effort focusing on the proceedings. This diversion of attention may materially adversely affect the conduct of our business, and, as a result, our financial condition and results of operations, particularly if the Chapter 11 proceedings are protracted.

During the pendency of the Chapter 11 proceedings, our employees will face considerable distraction and uncertainty, and we may experience increased levels of employee attrition. A loss of key personnel or material erosion of employee morale could have a material adverse effect on our ability to effectively, efficiently and safely conduct our business, and could impair our ability to execute our strategy and implement operational initiatives, thereby having a material adverse effect on our financial condition and results of operations.

Upon emergence from bankruptcy, the composition of our board of directors will change significantly.

Under the Plan, the composition of our board of directors will change significantly. Accordingly, a number of our board members will likely be new to the Partnership. Any new directors are likely to have different backgrounds, experiences and perspectives from those individuals who previously served on the board and, thus, may have different views on the issues that will determine the future of the Partnership. As a result, the future strategy and plans of the Partnership may differ materially from those of the past.

The Plan and any other plan of reorganization that we may implement will be based in large part upon assumptions and analyses developed by us. If these assumptions and analyses prove to be incorrect, our Plan may be unsuccessful in its execution.

The Plan and any other plan of reorganization that we may implement could affect both our capital structure and the ownership, structure and operation of our business and will reflect assumptions and analyses based on our experience and perception of historical trends, current conditions and expected future developments, as well as other factors that we consider appropriate under the circumstances. Whether actual future results and developments will be consistent with our expectations and assumptions depends on a number of factors, including but not limited to (i) our ability to change substantially our capital structure; (ii) our ability to obtain adequate liquidity and financing sources; (iii) our ability to maintain customers’ confidence in our viability as a continuing entity and to attract and retain sufficient business from them; (iv) our ability to retain key employees, and (v) the overall strength and stability of general economic conditions of the financial and oil and gas industries, both in the U.S. and in global markets. The failure of any of these factors could materially adversely affect the successful reorganization of our businesses.

In addition, the Plan and any other plan of reorganization will rely upon financial projections, including with respect to revenues, EBITDA, capital expenditures, debt service and cash flow. Financial forecasts are necessarily speculative, and it is likely that one or more of the assumptions and estimates that are the basis of these financial forecasts will not be accurate. In our case, the forecasts will be even more speculative than normal, because they may involve fundamental changes in the nature of our capital structure. Accordingly, we expect that our actual financial condition and results of operations will differ, perhaps materially, from what we have anticipated. Consequently, there can be no assurance that the results or developments contemplated by any plan of reorganization we may implement will occur or, even if they do occur, that they will have the anticipated effects on us and our subsidiaries or our business or operations. The failure of any such results or developments to materialize as anticipated could materially adversely affect the successful execution of any plan of reorganization.

Trading in our securities is highly speculative and poses substantial risks. Following effectiveness of the Plan and if the holders of unsecured claims vote in favor of the Plan, the holders of our existing common units will receive their pro rata share of 5% of the common units and warrants representing 10% of the new common units in the reorganized Partnership, which interests could be further diluted by the warrants and the management incentive plan contemplated by the Plan.

If the Plan, as contemplated in the RSA, is confirmed by the Bankruptcy Court and the holders of unsecured claims vote in favor of the Plan, then upon the Partnership’s emergence from Chapter 11, Noteholders will receive their pro rata share of (a) the new secured notes (the “New Secured Notes”) contemplated under the new second lien notes agreement that will be filed in connection with the Chapter 11 Cases, (b) the ownership interests in our reorganized general partner and (c) 95% of the new common units representing limited partnership interests in the reorganized Partnership issued and outstanding on the effective date of the reorganization prior to dilution by equity issued pursuant to the new management incentive plan and any issuances pursuant to the new warrants contemplated under the new warrants agreement that will be filed in connection with the Chapter 11 Cases. If the Plan as contemplated in the RSA is confirmed by the Bankruptcy Court and the holders of unsecured claims vote in favor of the Plan, the holders of the existing common units of the Partnership will receive their pro rata share of 5% of the new common units representing limited partnership interests and warrants representing 10% of the new common units representing limited partnership interest in the reorganized Partnership issued and outstanding on the effective date of the reorganization prior to dilution by equity issued pursuant to the new management incentive plan. If the Plan is confirmed by the Bankruptcy Court but the holders of unsecured claims vote against the Plan, then upon the Partnership’s emergence from Chapter 11, Noteholders will receive their pro rata share of (a) the New Secured Notes, (b) the ownership interest in our reorganized general partner and (c) 100% of the new common units representing limited partnership interests in the reorganized Partnership issued and outstanding on the effective date of the reorganization prior to dilution by equity issued pursuant to the new management incentive plan. Issuances of common units (or securities convertible into or exercisable for common units) under the management incentive plan and any exercises of the warrants for our common units will dilute the voting power of the outstanding common units and may adversely affect the trading price of such common units.

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, 2018. 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:

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

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, the Note Purchase Agreement and the DIP Facility 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 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.

You should also 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.

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, 2018. 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.

For the years ended December 31, 2018 and 2017, we incurred net losses of $128.5 million and $6.8 million, respectively. 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:

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.

Our insurance may not cover or be adequate to offset costs associated with certain events, claims and litigation, and there can be no assurance that insurance coverage will continue to be available in the future on terms that justify its purchase.

We maintain insurance against certain, but not all, hazards that could arise from our operations. 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. The occurrence of an event that is not insured or not fully insured could have a material adverse effect on the Company’s financial condition and results of operations in the future. In particular, as we are still assessing our exposure related to events, claims and litigation, there can be no assurance that our liability insurance will cover any or all costs associated with the incidents, which could have a material adverse effect on our financial condition and results of operations in the future.

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.

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 2018, our top five customers represented 62.7% 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 a portion 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.

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.

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, under which we would be obligated to pay despite any future decrease in the number of railcars needed to conduct our operations. Further, our agreement with CN requires us to provide minimum volumes of frac sand for shipping on the CN 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.

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 business, financial condition, results of operations or reputation.

We may record impairment charges on our assets that would adversely impact our results of operations and financial condition.

We are required to perform impairment tests on our assets if events or changes in circumstances modify the estimated useful life of or estimated future cash flows from an asset (such that the carrying amount of such asset may not be recoverable) or if management’s plans change with respect to such asset. An impairment in one period may not be reversed in a later period even if prices increase. If we are required to recognize impairment charges in the future, our results of operations and financial condition may be materially and adversely affected.

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 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 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.

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 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 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.

Our ability to incur additional debt is subject to limitations under our DIP Facility, Revolving Credit Facility and the Note Purchase Agreement. Further, as a result of our Chapter 11 Cases, we are extremely limited in our ability to borrow additional debt or access additional sources of financing and any such debt must be approved by the Bankruptcy Court. We do not have any contractual availability for further borrowings under our existing agreements at this time. Our level of debt has important consequences to us, including the following:

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 DIP Facility, Revolving Credit Facility and the Note Purchase Agreement 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 or delaying our business activities, acquisitions, investments or capital expenditures, selling assets, further 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 DIP Facility, Revolving Credit Facility and the Note Purchase Agreement limit our ability to capitalize on acquisition and other business opportunities.

The operating and financial restrictions and covenants in our DIP Facility, Revolving Credit Facility, the Note Purchase Agreement 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 DIP Facility, Revolving Credit Facility and the Note Purchase Agreement restrict or limit our ability to:

Furthermore, our DIP Facility, Revolving Credit Facility and the Note Purchase Agreement contain certain operating and financial covenants. Our ability to comply with the covenants and restrictions contained in our DIP Facility, Revolving Credit Facility and the Note Purchase Agreement may be affected by events beyond our control, including prevailing economic, financial and industry conditions. Prior to filing the Bankruptcy Petitions, we were in violation of certain covenants as a result of certain defaults under our Revolving Credit Facility and Note Purchase Agreement. We may be required to repay all or a portion of our debt on an accelerated basis in certain circumstances. If we fail to comply with the covenants and other restrictions in the agreements governing our debt, it could lead to an event of default and the acceleration of our repayment of outstanding debt. Our ability to comply with these covenants and other restrictions may be affected by events beyond our control, including prevailing economic and financial conditions. Any subsequent replacement of our DIP Facility, Revolving Credit Facility, the Note Purchase Agreement or any new indebtedness could have similar or greater restrictions.

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:

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.

Our current operations and future growth may require significant additional capital, and the amount and terms of our indebtedness could impair our ability to fund our capital requirements. The DIP Facility may be insufficient to fund our cash requirements through emergence from bankruptcy.

Our business requires substantial capital. We may require additional capital in the event of growth opportunities, unanticipated maintenance requirements, or significant departures from our current business plan. Additional financing may not be available on a timely basis or on terms acceptable to us and within the limitations contained in the DIP Facility. Failure to obtain additional financing, should the need for it develop, could impair our ability to fund capital expenditure requirements and meet debt service requirements and could have an adverse effect on our business.

Further, for the duration of the Chapter 11 Cases, we will be subject to various risks, including but not limited to (i) the inability to maintain or obtain sufficient financing sources for operations or to fund the plan of reorganization and meet future obligations, and (ii) increased legal and other professional costs associated with the Chapter 11 Cases and our reorganization.

If the transactions contemplated by the plan of reorganization are not completed and the effective date of the plan of reorganization does not occur prior to the maturity of the DIP Facility, we may need to refinance the DIP Facility. We may not be able to obtain some or all of any such financing on acceptable terms or at all.

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

We may be able to incur additional indebtedness in the future, subject to certain limitations, including under the DIP Facility, and the exit facilities contemplated in the Plan. 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.

Further, under Chapter 11, transactions outside the ordinary course of business are subject to the prior approval of the Bankruptcy Court, which may limit our ability to respond in a timely manner to certain events or take advantage of certain opportunities or to adapt to changing market or industry conditions. The Debtors are subject to various covenants and events of default under the DIP Facility. In general, certain of these covenants limit the Debtors’ ability, subject to certain exceptions, to take certain actions, including:

If the Debtors fail to comply with these covenants or an event of default occurs under the DIP Facility, our liquidity, financial condition or operations may be materially impacted. We are currently in an event of default under the DIP Facility as described above under “Item 1. Business—DIP Facility.”

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. 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:

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.

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.

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.

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.

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.

Although Insight Equity has delegated certain of its authorities to the Committee under the RSA, it owns the majority of and controls our general partner and appointed the majority of our 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:

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:

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:

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:

Furthermore, we expect that your existing ownership interests will be subject to significant dilution pursuant to the terms of the RSA and may be eliminated entirely. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources”.

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.

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:

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.

As a result of the delisting of our common units on NYSE, our common units are currently traded on over-the-counter markets, which could adversely affect the market liquidity of our common units and harm our business.

On May 31, 2019, the NYSE notified us that the NYSE Regulation had determined to commence proceedings to delist our common units from the NYSE due to our continued non-compliance with the continued listing standard set forth in Section 802.01B of the NYSE Listed Company Manual, which requires the listed company to maintain an average global market capitalization over a consecutive 30 day trading period of at least $15,000,000. As a result, the NYSE suspended trading of our common units at the close of trading on May 31, 2019 and our common units were delisted from the NYSE on June 17, 2019. On June 1, 2019, our common units began trading over-the-counter, under the trading symbol “EMESZ”.

Securities traded over-the-counter are usually thinly traded, highly volatile, have fewer market makers and are not followed by analysts. Trading over-the-counter may result in a reduction in some or all of the following, each of which could have a material adverse effect on our unitholders:

Further, since our common units were delisted from the NYSE, we are subject to fewer rules and regulations, including with respect to corporate governance, than if our common units were traded on the NYSE. Without required compliance of these corporate governance standards, investor interest in our common units may decrease.

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.

As reported in “Item 9A—Controls and Procedures” contained in this report, management identified a material weakness in our internal control over financial reporting for the fiscal year ended December 31, 2018.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud, and operate successfully as a public company. If additional material weaknesses or significant deficiencies in our internal control over financial reporting are discovered or occur in the future, there exists a risk that our consolidated financial statements may contain material misstatements that are unknown to us at that time, and such misstatements could require us to restate our financial results. We or our independent registered public accounting firm may identify other material weaknesses in our internal control over financial reporting in the future. 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.

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.

The Chapter 11 Cases could have significant adverse tax consequences to our unitholders.

The Chapter 11 Cases may result in significant cancellation of debt (“COD”) income to our unitholders. As described below, any COD income may cause a unitholder to be allocated income with respect to our units with no corresponding distribution of cash to fund the payment of the resulting tax liability to the unitholder. In addition, we may engage in transactions that trigger a unitholder’s tax gain or loss with respect to our units. A transaction that triggers a unitholder’s gain may not be accompanied by any receipt of cash to fund the payment of the resulting tax liability to the unitholder. Under certain circumstances, a unitholder’s loss upon any such transaction may be permanently disallowed.

Entities taxed as corporations may have net operating losses to offset COD income or may otherwise qualify for an exception to the recognition of COD income, such as the bankruptcy or insolvency exceptions. In the case of partnerships like ours, however, these exceptions are not available to the partnership and are only available to a unitholder if the unitholder itself is insolvent or in bankruptcy. As a result, these exceptions generally would not apply to prevent the taxation of COD income allocated to our unitholders. The ultimate tax effect of any such income allocations will depend on the unitholder’s individual tax position, including, for example, the availability of any suspended passive losses that may offset some portion of the allocable COD income. The suspended passive losses available to offset COD income will increase the longer a unitholder has owned our units. Unitholders may, however, be allocated substantial amounts of ordinary income subject to taxation, without any ability to offset such allocated income against any capital losses attributable to the unitholder’s ultimate disposition of its units. Unitholders are encouraged to consult their tax advisors with respect to the consequences to them of COD income

We urge our unitholders to consult their tax advisors regarding the potential adverse effects of the various strategic alternatives that may be available to us.

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 our unitholders will be allocated taxable income that could be different in amount from the cash we distribute, they will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income, whether or not they receive any cash distributions 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 their share of our taxable income.

For example, a unitholder’s share of our taxable income will include any COD income recognized upon the satisfaction of our outstanding indebtedness for total consideration less than the adjusted issue price (and any accrued but unpaid interest) of such indebtedness. As described above, depending upon the net amount of other items related to our loss (or income) allocable to a

unitholder, any COD income may cause a unitholder to be allocated income with respect to our units with no corresponding distribution of cash to fund the payment of the resulting tax liability to the unitholder. Furthermore, such COD income event may not be fully offset, either now or in the future, by capital losses, which are subject to significant limitations, or other losses. Accordingly, a COD income event could cause a unitholder to realize taxable income without corresponding future economic benefits or offsetting tax deductions.

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.

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.

A unitholder whose common units are loaned to a “short seller” to affect 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.

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

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

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.

In March 2019, we sued EP Energy Corporation for failure to purchase minimum contract volumes under a sand supply agreement with us. We are seeking damages and the case remains on-going.

In June 2018, an employee of Emerge was fatally injured at our San Antonio mine. MSHA investigated the incident and issued three citations, which Emerge is contesting. In addition, the employee’s family has filed a lawsuit against Emerge in the 45^th Judicial District, Bexar County, Texas on May 6, 2019. The lawsuit is being defended by Emerge’s workman compensation insurer; however, there can be no assurance that our liability insurance will cover any or all costs related to the incident, which could have a material adverse effect on our financial position, liquidity or results of operations. Currently, the lawsuit stayed due to Emerge’s Chapter 11 Cases, but Emerge intends to defend vigorously.

On July 15, 2019, the Debtors filed Bankruptcy Petitions in the United States Bankruptcy Court for the District of Delaware seeking relief under the provisions of Chapter 11 of the Bankruptcy Code. The commencement of the Chapter 11 proceedings automatically stayed certain actions against the Company, including actions to collect pre-petition liabilities or to exercise control over the property of the Debtors. The Plan in our Chapter 11 proceedings provides for the treatment of pre-petition liabilities that have not otherwise been satisfied or addressed during the Chapter 11 cases. We expect the Plan to become effective in November 2019, at which point the Debtors would emerge from bankruptcy, however, there can be no assurance that the effectiveness of the Plan will occur on such date, or at all. For more information regarding the Plan and the Debtors’ Chapter 11 Cases, please see “Item 1. Business—Overview—Reorganization and Chapter 11 Proceedings.”

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 previously owned 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, a previously owned subsidiary, 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.

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 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.

On June 1, 2019, our common units commenced trading over-the-counter under the symbol “EMESZ”. Any over-the-counter market quotations reflect inter-dealer prices, without retail mark-up, markdown or commission and may not necessarily represent actual transactions. Prior to June 1, 2019, our common units were listed on the New York Stock Exchange. Prior to May 14, 2003, our common units were not listed on any exchange or traded in any public market. On May 31, 2019, the closing market price for the common units was $0.21 per unit. As of September 30, 2019, there were 31,185,729 common units outstanding. There were 25,076 record holders of common units on December 31, 2018. 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 2018, and 2017:

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 Revolving Credit Facility, 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 — Revolving Credit Facility”.

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.

See Item 12. “Security Ownership of Certain Beneficial Owners and Management and Related Unitholders Matters-Securities Authorized for Issuance Under Equity Compensation Plans” for information regarding our equity compensation plans as of December 31, 2018.

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:

	Year Ended December 31,
	2018			2017			2016			2015			2014

	($ in thousands, except per unit data)
Statement of Operations Data:
Revenues	$	313,590		$	364,302		$	128,399		$	269,518		$	341,836
Operating expenses:
Cost of goods sold (excluding depreciation, depletion and amortization)		257,922			304,279			173,907			209,161			204,282
Depreciation, depletion and amortization		19,633			21,899			19,126			17,897			12,805
Asset impairment (6)		105,645			—			—			—			—
Selling, general and administrative expenses		26,769			26,796			20,951			27,551			32,231
Contract and project terminations		1,689			—			4,011			10,652			—
Total operating expenses		411,658			352,974			217,995			265,261			249,318
Income (loss) from operations		(98,068	)		11,328			(89,596	)		4,257			92,518
Other expense (income):
Interest expense, net		30,993			19,171			21,339			11,216			6,343
Loss on extinguishment of debt		1,906			—			—			—			—
Other expense (income)		(2,571	)		(4,207	)		2,471			(34	)		649
Total other expense		30,328			14,964			23,810			11,182			6,992
Income (loss) from continuing operations before provision for income taxes		(128,396	)		(3,636	)		(113,406	)		(6,925	)		85,526
Provision (benefit) for income taxes		147			71			(191	)		258			205
Net income (loss) from continuing operations		(128,543	)		(3,707	)		(113,215	)		(7,183	)		85,321
Discontinued Operations
Income (loss) from discontinued operations, net of taxes		—			(3,125	)		8,746			(2,228	)		3,758
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
Net income (loss)	$	(128,543	)	$	(6,832	)	$	(72,770	)	$	(9,411	)	$	89,079

Earnings (loss) per common unit
Basic:
Earnings (loss) per common unit from continuing operations	$	(4.14	)	$	(0.12	)	$	(4.55	)	$	(0.30	)	$	3.54
Earnings (loss) per common unit from discontinued operations		—			(0.11	)		1.63			(0.09	)		0.16
Basic earnings (loss) per common unit	$	(4.14	)	$	(0.23	)	$	(2.92	)	$	(0.39	)	$	3.70
Diluted:
Earnings (loss) per common unit from continuing operations	$	(4.14	)	$	(0.12	)	$	(4.55	)	$	(0.30	)	$	3.54
Earnings (loss) per common unit from discontinued operations		—			(0.11	)		1.63			(0.09	)		0.16
Diluted earnings (loss) per common unit	$	(4.14	)	$	(0.23	)	$	(2.92	)	$	(0.39	)	$	3.70
Balance Sheet Data (at year end):
Property, plant and equipment, net	$	140,384		$	185,970		$	165,855		$	179,250		$	188,545
Total assets	$	211,419		$	300,116		$	241,078		$	420,048		$	432,127
Long-term debt (1)	$	—		$	176,351		$	134,012		$	295,938		$	217,023
Statement of Cash Flow Data:
Net cash provided by (used in):
Operating activities	$	33,855		$	(2,103	)	$	(47,326	)	$	47,325		$	86,161
Investing activities	$	(77,367	)	$	(27,667	)	$	140,541		$	(33,674	)	$	(88,172	)
Financing activities	$	41,342		$	35,495		$	(114,081	)	$	343		$	6,720
Capital expenditures:
Maintenance (2)	$	(1,133	)	$	(1,540	)	$	(1,808	)	$	(2,344	)	$	(3,240	)
Growth (3)		(77,422	)		(5,908	)		(11,715	)		(33,130	)		(74,644	)
Total	$	(78,555	)	$	(7,448	)	$	(13,523	)	$	(35,474	)	$	(77,884	)
Other Financial Data:
Cash dividends declared per common unit (4)		—			—			—		$	3.08		$	4.68
Adjusted EBITDA (5)	$	35,701		$	44,983		$	(37,354	)	$	50,704		$	132,827

	Quarter
	First			Second			Third			Fourth

	($ in thousands, except per unit data)
2018:
Revenues	$	106,750		$	101,842		$	62,961		$	42,037
Operating income (loss)	$	11,387		$	16,447		$	1,615		$	(127,517	)
Net income (loss) from continuing operations	$	1,486		$	9,428		$	(3,853	)	$	(135,604	)
Total income (loss) from discontinued operations, net of tax	$	—		$	—		$	—		$	—
Net income (loss)	$	1,486		$	9,428		$	(3,853	)	$	(135,604	)
Basic earnings (loss) per common unit
Continuing operations	$	0.05		$	0.30		$	(0.12	)	$	(4.37	)
Discontinued operations		—			—			—			—
Basic earnings (loss) per common unit	$	0.05		$	0.30		$	(0.12	)	$	(4.37	)
Diluted earnings (loss) per common unit
Continuing operations	$	0.05		$	0.30		$	(0.12	)	$	(4.37	)
Discontinued operations		—			—			—			—
Diluted earnings (loss) per common unit	$	0.05		$	0.30		$	(0.12	)	$	(4.37	)
Cash dividends declared per common unit	$	—		$	—		$	—		$	—

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	$	—		$	—		$	—		$	—

We calculate Adjusted EBITDA, a non-GAAP measure, in accordance with our Revolving Credit Facility in effect as of December 31, 2018 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:

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.

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 Revolving Credit Facility in effect as of December 31, 2018.

	Continuing			Discontinued		Consolidated

	Year Ended December 31, 2018

	($ in thousands)
Net income (loss)	$	(128,543	)	$	—	$	(128,543	)
Interest expense, net		30,993			—		30,993
Depreciation, depletion and amortization		19,633			—		19,633
Provision (benefit) for income taxes		147			—		147
EBITDA		(77,770	)		—		(77,770	)
Equity-based compensation expense		1,507			—		1,507
Write-down of sand inventory		4,694					4,694
Loss on extinguishment of debt		1,906			—		1,906
Contract and project terminations		1,689			—		1,689
Provision for doubtful accounts		310			—		310
Accretion expense		122			—		122
Retirement of assets		619			—		619
Asset impairments		105,645					105,645
Other state and local taxes		1,817			—		1,817
Non-cash deferred lease expense		(3,457	)		—		(3,457	)
Unrealized (gain) loss on fair value of warrant		(2,530	)		—		(2,530	)
Other adjustments allowable under our Credit Agreement		1,149			—		1,149
Adjusted EBITDA	$	35,701		$	—	$	35,701

	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 warrant		(4,208	)		—			(4,208	)
Other adjustments allowable under our Credit Agreement		213			—			213
Adjusted EBITDA	$	44,983		$	—		$	44,983

	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 warrant		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	)

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

	Year Ended December 31,
	2018			2017			2016			2015			2014

	($ in thousands)
Adjusted EBITDA	$	35,701		$	44,983		$	(37,354	)	$	50,704		$	132,827
Interest expense, net		(22,716	)		(15,497	)		(16,672	)		(11,729	)		(5,727	)
Income tax expense		(1,964	)		(1,967	)		(1,948	)		(2,777	)		(2,239	)
Contract and project terminations - non-cash		—			—			(3	)		(307	)		689
Reduction in force		—			—			(76	)		(362	)		—
Write-down of sand inventory		(4,694	)		—			(5,394	)		—			—
Other adjustments allowable under our existing credit agreement		(1,149	)		(213	)		(209	)		—			—
Cost to retire assets		—			19			9			—			—
Non-cash deferred lease expense		3,457			(8,035	)		(5,758	)		—			—
Change in other operating assets and liabilities		25,220			(21,393	)		20,079			11,796			(39,389	)
Cash flows from operating activities:	$	33,855		$	(2,103	)	$	(47,326	)	$	47,325		$	86,161

Cash flows from investing activities:	$	(77,367	)	$	(27,667	)	$	140,541		$	(33,674	)	$	(88,172	)

Cash flows from financing activities:	$	41,342		$	35,495		$	(114,081	)	$	343		$	6,720

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.

Our consolidated financial statements for the fiscal year ended December 31, 2018 were prepared on a going concern basis in accordance with GAAP. The going concern basis of presentation assumes that we will continue in operation and be able to realize our assets and discharge our liabilities and commitments in the normal course of business.

During 2018 and especially the fourth quarter, we experienced significant losses and negative cash flows from operations. We incurred a net loss of $128.5 million for the year ended December 31, 2018 and have $267.8 million in current liabilities as of December 31, 2018. We had negative working capital and, prior to filing the Chapter 11 Cases, we delayed payments to our vendors, did not make payments to certain vendors and payments under certain contractual obligations, and were in default under our Revolving Credit Agreement, Note Purchase Agreement and certain other contractual obligations. In addition, as noted in our auditor’s report, we face liquidity challenges. These factors, among others, raise substantial doubt about our ability to continue as a going concern. Our consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty. There are no assurances we will be successful in our efforts to reduce our obligations and report profitable operations or to continue as a going concern, in which event investors may lose their entire investment.

As previously disclosed, we engaged a Chief Restructuring Officer and other advisors to assist in efforts to restructure our various long-term contracts. On April 18, 2019, we entered into the RSA pursuant to which we have agreed to the principal terms of a proposed financial restructuring of the Partnership. On July 15, 2019, the Debtors filed Bankruptcy Petitions in the United States Bankruptcy Court for the District of Delaware seeking relief under the provisions of Chapter 11 of the Bankruptcy Code. The commencement of the Chapter 11 proceedings automatically stayed certain actions against the Debtors, including actions to collect pre-petition liabilities or to exercise control over the property of the Debtors. The Plan in our Chapter 11 proceedings provides for the treatment of pre-petition liabilities that have not otherwise been satisfied or addressed during the Chapter 11 Cases. We expect the Plan to become effective in November, 2019, at which point the Debtors would emerge from bankruptcy, however, there can be no assurance that the effectiveness of the Plan will occur on such date, or at all. See “Liquidity and Capital Resources” for further details on the RSA and the Chapter 11 Cases.

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.

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”.

We calculate Adjusted EBITDA, a non-GAAP measure, in accordance with our Revolving Credit Facility in effect as of December 31, 2018, 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:

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.

Demand for frac sand decreased during 2016 as a result of the industry downturn. However, commodity prices stabilized in the middle of 2016, leading to an improvement in drilling activities during the second half of 2016 and into 2017. Market conditions improved significantly in 2017 resulting in an increased demand and pricing for frac sand. The market for frac sand began to soften again in early August 2018, due to a decline in well completion activities as well as oil and natural gas exploration and production companies’ budget exhaustions. These factors, along with the new production from in-basin frac sand competitors discussed below, led the sand market to quickly turn from a state of short supply in the first half of the year to oversupply in the second half of 2018 and into 2019. As a result, the entire industry has experienced pricing pressure, particularly on the northern white product. Through 2019, market conditions have remained weak. In fact, oil and gas companies are strictly adhering to their capital budgets in a response to investors demanding a return of their capital as opposed to funding growth.

We continue to enter into multi-year contracts with some of our key accounts. We are also executing take-or-pay sand supply agreements for our San Antonio operation. We believe that sand supply agreements ensure the customers a steady supply of product in exchange for covering fixed costs plus needed margins associated with operating our business.

Based on a shift in some customers’ preference for lower-quality sand, our competitors have built in-basin frac sand operations targeting the Permian Basin in West Texas, the Eagle Ford Shale in South Texas, and Mid-Continent in Oklahoma. There can be no assurances that all the announced projects will be completed given permitting, construction, infrastructure, and environmental constraints. Our San Antonio operation positions us to target the Eagle Ford Shale which is the second most active Texas in-basin market.

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 than northern white sands, so several 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. Additionally, the amount of proppant pumped downhole per horizontal well continues to increase. 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 acquisition in San Antonio, we have two Texas operations that are well positioned geographically to meet the demand in the Texas basins. Upon completion, our new Kingfisher, Oklahoma site will allow us to serve customers in-basin for the Mid-Continent region.

On April 12, 2017, we acquired our San Antonio facility. 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 constructed new wet and dry plants on the site. The new dry plant commenced operations in late April 2018. Full construction of the dry and wet plant was completed in January 2019. Our San Antonio reserves contain API-specification, strategic reserves (40/70 and 100 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 San Antonio plant to the Eagle Ford Shale, we sell all of the frac sand produced at the San Antonio plant into the Eagle Ford Shale, which is currently the second most active in the United States.

We faced significant construction delays at our San Antonio facility. Our inability to complete construction and ramp up production on our originally projected timeline has negatively impacted our operating cash flows, profitability, and liquidity.

We often enter into multi-year contracts with third parties for agreements that include railcar leases, transload terminal leases, and minimum volume mining contracts. During periods of business expansion, we typically enter into new arrangements with various third parties, or we increase commitments with existing third parties. During periods of business contraction, we work with our providers to lower our fixed cost obligations. We have achieved some success on reducing fixed costs during periods of business contraction. In the second quarter of 2018, we successfully deployed all our railcars back into service. However, with the market shift from northern white sand and terminal sales, by December 31, 2018 we had 871 railcars in storage, and the storage count increased to over 2,700 as we filed the Chapter 11 Cases. As part of our bankruptcy filing, we have rejected railcar and transload leases where we are paying above market rates or do not need access to the asset. We expect a significant reduction in the annual fixed costs as certain leases were rejected and as we have agreed to retain 1,450 railcars under our new lease agreements. There is no assurance that we will be able to negotiate price concessions and purchase commitment amendments from our major vendors.

In light of the market conditions for northern white sand, we have temporarily idled our higher cost mines and plants, and shortened the mining season at our Wisconsin mines in 2019, in order to reduce our operating costs and conserve liquidity.

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. The cost of deferring future railcar deliveries was recorded as a deferred lease asset. We are entering into new, amended railcar leases with three select lessors through the Chapter 11 Cases on new terms to match the fleet size and economics for our railcars to the current market environment.

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 5 to our Consolidated Financial Statements for a detailed discussion of the sale of the Fuel business.

We have developed our sand distribution system 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. As in-basin sand gains market share, this logistic network has unabsorbed fixed costs in the current northern white sand market environment. As part of our bankruptcy process, we rejected all railcar and select transload leases where we were paying above market rates or did not need access to the asset. Additionally, we entered into new railcar leases on amended terms with three select railcar lessors. We expect a significant reduction in the annual fixed costs from the rejection and where applicable re-negotiation of these leases.

In early 2016, we launched our self-suspending sand marketed under the brand SandMaxX™. This new technology offered the potential to increase production in oil and gas wells in addition to improving pump time and reducing other upfront costs. Trial wells proved that the technology is effective down-hole, but the customer adoption rate was slower than initially anticipated. Under the contract, we had the option to continue ownership of this technology after the initial installment period (which expired on May 25, 2018) by payment of significant additional funds. Given the lack of market acceptance for SandMaxX™ proppant, even after considerable efforts to market the product, we elected to discontinue ownership of the intellectual property after the initial installment period. This did not have a material impact on our financial position or results of operations.

The frac sand market has grown from approximately 40 million tons of demand in 2016 to 85 million tons in 2018. However, the demand for frac sand deteriorated in the second half of the year as lower commodity prices and constrained takeaway capacity infrastructure forced oil and gas companies to pull back on drilling and completion activity. The industry outlook remains uncertain with oil and gas companies reducing their 2019 capital budgets. After two years of rapid production growth, oil and gas companies appear to be shifting their strategy to living within operating cash flows instead of relying upon outside financing, which can be difficult to obtain in times of commodity price volatility. Overall, this should be a positive development for the industry as North American energy producers have lowered their production costs through technological innovation and can now better compete in the global energy markets. This more disciplined approach should generate more sustainable growth and returns for both the oil and gas and frac sand industries.

While the demand for frac sand has levelled off recently, new supply continues to enter the market mostly in the form of local in-basin mines. Over 120 million tons per year of new in-basin capacity is either online or under construction, bringing the total market supply to over 240 million tons per year including northern white and regional mines. This imbalance has created pricing pressure and has caused several higher cost plants to shut down or temporarily idle, including our Arland plant in Wisconsin. Frac sand prices fell dramatically to end 2018, and further price reductions could occur to finish 2019 due to market over supply.

The following table summarizes our consolidated operating results for 2018, 2017, and 2016.

	Year Ended December 31,
	2018			2017			2016

	($ in thousands)
Revenues	$	313,590		$	364,302		$	128,399
Operating expenses:
Cost of goods sold (excluding depreciation, depletion and amortization)		257,922			304,279			173,907
Depreciation, depletion and amortization		19,633			21,899			19,126
Asset impairments		105,645
Selling, general and administrative expenses		26,769			26,796			20,951
Contract and project terminations		1,689			—			4,011
Total operating expenses		411,658			352,974			217,995
Operating income (loss)		(98,068	)		11,328			(89,596	)
Other expense (income):
Interest expense, net		30,993			19,171			21,339
Loss on extinguishment of debt		1,906			—			—
Other		(2,571	)		(4,207	)		2,471
Total other expense		30,328			14,964			23,810
Income (loss) from continuing operations before provision for income taxes		(128,396	)		(3,636	)		(113,406	)
Provision (benefit) for income taxes		147			71			(191	)
Net income (loss) from continuing operations		(128,543	)		(3,707	)		(113,215	)
Discontinued Operations
Income (loss) from discontinued operations, net of taxes		—			(3,125	)		8,746
Gain on sale of discontinued operations		—			—			31,699
Total income (loss) from discontinued operations, net of tax		—			(3,125	)		40,445
Net income (loss)	$	(128,543	)	$	(6,832	)	$	(72,770	)
Adjusted EBITDA (a)	$	35,701		$	44,983		$	(37,354	)

Our company has experienced significant change over the past three years, declining from a net loss of $72.8 million in 2016, to a net loss of $6.8 million in 2017, and an increasing net loss of $128.5 million in 2018. Most notable are the following events:

	Year Ended December 31,
	2018			2017			2016

	($ in thousands)
Revenues:
Frac sand revenues	$	309,758		$	359,941		$	127,873
Non-frac sand revenues		3,832			4,361			526
Total revenues	$	313,590		$	364,302		$	128,399
Operating expenses:
Cost of goods sold (excluding depreciation, depletion and amortization)		257,922			304,279			173,907
Depreciation, depletion and amortization		19,633			21,899			19,126
Asset impairments		105,645
Selling, general and administrative expenses		26,769			26,796			20,951
Contract and project terminations		1,689			—			4,011
Total operating expenses		411,658			352,974			217,995
Operating income (loss)	$	(98,068	)	$	11,328		$	(89,596	)
Net income (loss) from continuing operations	$	(128,543	)	$	(3,707	)	$	(113,215	)
Adjusted EBITDA (a)	$	35,701		$	44,983		$	(50,425	)

Volume of frac sand sold (tons in thousands)		4,631			5,221			2,134
Volume of non-frac sand sold (tons in thousands)		286			312			23
Total volume of sand sold (tons in thousands)		4,917			5,533			2,157

Terminal sand sales (tons in thousands)		1,373			2,448			1,240

Volume of frac sand produced by plant (tons in thousands):
Arland, Wisconsin facility		1,075			1,800			186
Barron, Wisconsin facility		1,577			2,081			1,588
New Auburn, Wisconsin facility		1,017			1,272			352
San Antonio, Texas facility (b)		638			50			—
Kosse, Texas facility		383			231			140
Total volume of frac sand produced		4,690			5,434			2,266

The net loss for our sand business saw substantial improvement from a loss of $113.2 million in 2016, to a net loss of $3.7 million in 2017, due to an improvement in drilling activity during the third quarter of 2016, and into 2017. While prices generally increased throughout the entirety of 2017, prices increased during the first half of 2018 as the industry struggled to deliver enough volumes to keep pace with surging demand. The market for frac sand began to soften in early August 2018, due to a decline in well completion activities as well as oil and natural gas exploration and production companies’ budget exhaustions. These factors, along with the new production from in-basin frac sand competitors discussed below, led the sand market to quickly turn from a state of short supply in the first half of the year to oversupply in the second half of 2018. As a result, the entire industry experienced pricing pressure, particularly on the northern white product. This led to an increase in net loss to $128.5 million in 2018. During the downturn, we shifted our transload locations to better align with the needs of our customers. At December 31, 2018, we had 13 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.

Sand revenues decreased by $50.7 million primarily due to a 11% decrease in total volumes sold resulting from a shift in mix away from higher-priced terminal sales and a slowdown in well completion activities in the second half of 2018. FOB plant sales volumes increased 15% compared to a 44% decrease in the higher-priced, terminal sand sales. Terminal sales as a percentage of total volumes sold decreased from 44% in 2017 to 28% in 2018. Revenue per ton decreased to $63.78 in 2018 compared to $65.84 per ton in 2017, due to lower northern white volumes sold, shift in mix away from higher-priced terminal sales and a decline in northern white prices.

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 increased with our higher sales but was offset by decreased logistic costs. The most significant components of the $46.4 million decrease from 2017 to 2018 are:

Depreciation, depletion and amortization decreased by $2.3 million mainly due to higher depletion expense in 2017 as mines were open the full year compared to 2018 when we shut down our Wisconsin mines early. This decrease was offset by the addition of our San Antonio facility in 2018.

During the fourth quarter of 2018, we experienced a sharp decline in the demand for northern white sand, the primary product of our Wisconsin mines and plants. Accordingly, we performed impairment testing of this asset group by estimating the future undiscounted net cash flows using estimates of future sales prices and volumes (considering historical prices, 2018 sales trends and related market factors) as well as operating costs in relation to the carrying value of these assets. Our analysis determined the undiscounted cash flows were less than the carrying amount of the asset group and thus we hired a third party to assist us in performing the discounted cash flow analysis. The discounted cash flow analysis resulted in a nominal economic value. Therefore, the fair value of the assets

was estimated using Level 2 and Level 3 inputs based on the orderly liquidation value (“OLV”). The OLV considered market quotes and the valuation of similar assets. Emerge recorded a non-cash charge of $105.6 million of long-lived asset impairments.

During the year ended December 31, 2018, we recorded a non-cash charge against earnings of $1.7 million. This charge relates to the write-off of prepaid royalties. See Note 15 to our Consolidated Financial Statements for further discussion.

In connection with the Note Purchase Agreement Amendment described in Note 12 to our Consolidated Financial Statements, we recognized a $1.9 million loss on extinguishment on a portion of our debt, which mainly represents the difference between the fair value and carrying value of debt, write-off of all remaining unamortized debt issuance costs, and unamortized original issuance discount.

Other expenses decreased $1.6 million due to a lower mark-to-market net gain recognized in 2018 for a change in the fair value of the warrant issued in August 2016.

Sand revenues increased 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.

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:

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.

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

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

Other expenses decreased $6.7 million due to a non-cash mark-to-market gain of $2.5 million during the year ended December 31, 2017, compared to a gain of $4.2 million during the year ended December 31, 2016.

We sold our Fuel business in August 2016 and recognized a gain of $31.7 million, thus the results of operations of the Fuel business have been classified as discontinued operations for all periods presented.

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

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.

On April 18, 2019, we entered into a Restructuring Support Agreement (the “RSA”) with (i) each of our direct and indirect subsidiaries, and the direct and indirect owners of our general partner (the “Consenting Equity Holders”), (ii) HPS Investment Partners, LLC (“HPS”) and certain of the lenders under the Revolving Credit Facility (the “Revolving Loan Lenders”), and (iii) HPS and certain holders of the Company’s Notes (the “Noteholders,”).

As set forth in the RSA, the parties to the RSA have agreed to the principal terms of a proposed financial restructuring (the “Transaction”) of the Partnership. For an In-Court Reorganization implemented in one or more cases filed under Title 11 of the United States Code (the “In-Court Reorganization”), the RSA provides, in pertinent part, that, if the class of holders of General Unsecured Claims vote to accept the Chapter 11 plan, then the Consenting Noteholders have agreed to carve-out from their collateral and receipt of 100% of the New Common Units in us a settlement fund to be shared collectively by such claimholders and the existing equity holders in us consisting of the New Common Units.

However, in the event that the class of holders of General Unsecured Claims vote to reject the Chapter 11 plan, then such Holders and our existing equity holders shall not receive any distributions or property under the Chapter 11 plan and, accordingly, the Consenting Noteholders shall receive 100% of the New Common Units in us, subject to certain types of dilution.

The RSA may be terminated upon, among other things, the earliest of the following to occur: (i) the Transaction is consummated; (ii) the Transaction is not consummated in accordance with the RSA by December 31, 2019; unless extended in writing by us, our general partner and the Majority Noteholders; (iii) the parties to the RSA mutually agree in writing to such termination; (iv) certain breaches of the RSA by one of the parties to the RSA (that remain uncured for five (5) business days); or (v) we or the Consenting Creditors terminate the RSA.

On July 15, 2019, we voluntarily filed for bankruptcy under Chapter 11 of the Bankruptcy Code. These factors, among others, raise substantial doubt about our ability to continue as a going concern. In addition, as noted in our auditor’s report, we face liquidity challenges and, prior to filing the Chapter 11 Cases, we were in default under our Revolving Credit Facility, Note Purchase Agreement and other contractual obligations. Our consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

On July 19, 2019, we entered into a $35 million DIP Facility. Our sources of liquidity during the Chapter 11 Cases include cash generated by our operations and borrowings under our DIP Facility. As of September 30, 2019, we had $15.0 million drawn under the Commitment Amount. Our ability to meet DIP Facility requirements is dependent on our ability to generate sufficient cash flows from operations and meet certain milestones.

Events of default have occurred under the DIP Facility and due to such events of default, the lenders are charging default interest equal to an additional 2% on all obligations thereunder. The DIP Facility allows for continued advances during an event of default in the DIP Administrative Agent’s sole discretion. Following the conclusion of the Chapter 11 Cases, there can be no assurance that cash flows from operations and debt financing will continue to be sufficient to enable us to continue to fund our operations.

When the plan of reorganization is implemented in a bankruptcy proceeding, it is possible that holders of claims and interests with respect to, or rights to acquire, our equity securities would be entitled to little or no recovery, and those claims and interests may be canceled for little or no consideration. If that were to occur, we anticipate that all or substantially all of the value of all investments in our equity securities would be lost and that our unitholders would lose all or substantially all of their investment. It is also possible that our other stakeholders, including our secured and unsecured creditors, will receive substantially less than the amount of their claims. There are no assurances we will be successful in our efforts to reduce our obligations and report profitable operations or to continue as a going concern, in which event investors may lose their entire investment.

Under the Bankruptcy Code, the Debtors may assume, assign, or reject certain executory contracts and unexpired leases subject to the approval of the Bankruptcy Court and certain other conditions. Generally, the rejection of an executory contract or unexpired lease is treated as a pre-petition breach of such executory contract or unexpired lease and, subject to certain exceptions, relieves the Debtors of performing their future obligations under such executory contract or unexpired lease but entitles the contract counterparty or lessor to a pre-petition general unsecured claim for damages caused by such deemed breach. Counterparties to such rejected contracts or leases may assert claims against the applicable Debtor's estate for such damages. Generally, the assumption of an executory contract or unexpired lease requires the Debtors to cure existing monetary defaults under such executory contract or unexpired lease and provide adequate assurance of future performance. Accordingly, any description of an executory contract or unexpired lease with the Debtors in this Annual Report, including where applicable a quantification of our obligations under any such executory contract or unexpired lease with the Debtors is qualified by any overriding rejection rights we have under the Bankruptcy Code. Further, nothing herein is or shall be deemed an admission with respect to any claim amounts or calculations arising from the rejection of any executory contract or unexpired lease and the Debtors expressly preserve all of their rights with respect thereto.

We expect the Plan to become effective in November, 2019, at which point the Debtors would emerge from bankruptcy. The Debtors commenced solicitation for the Plan on September 13, 2019. While we anticipate substantially all of our $338 million of indebtedness will be discharged upon emergence from Chapter 11 bankruptcy, there is no assurance that the effectiveness of the Plan will occur in November, 2019, or at all. The filing of the Bankruptcy Petitions constituted an event of default that accelerated the Partnership’s obligations under all of its outstanding debt instruments, resulting in the principal and interest due thereunder immediately due and payable. However, any efforts to enforce such payment obligations were automatically stayed as a result of the filing of the Chapter 11 Cases, and the creditors’ rights of enforcement in respect of the debt instruments were subject to the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court

On April 12, 2017, 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 (“PNC Bank”), as administrative agent and collateral agent (the “agent”), and the lenders thereto. 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.

On January 5, 2018, we entered into a $75.0 million Second Amended and Restated Revolving Credit and Security Agreement (the “Revolving Credit Agreement”), among the Partnership, as parent guarantor, the Borrowers, as borrowers, PNC Bank, as administrative agent and collateral agent, and the other lenders party thereto (together with PNC Bank, the “Revolving Lenders”). The Revolving Credit Agreement replaced the Prior Credit Agreement. The Revolving Credit Facility 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 Revolving Credit Agreement matures on January 5, 2022. Substantially all our assets are pledged as collateral on a first lien basis. The 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 Revolving Credit Agreement contains various covenants and restrictive provisions and also requires the maintenance of certain financial covenants as follows:

Loans under the Revolving Credit Facility 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.

At December 31, 2018, our outstanding borrowings under the Revolving Credit Facility bore interest at a weighted-average rate of 8.7%. Following our default on certain financial covenants as of December 31, 2018, the base rate on all borrowings under the Revolving Credit Facility increased by 2%.

On December 31, 2018, we entered into the Forbearance Agreement and First Amendment to Revolving Credit Agreement (the “Revolving Credit Agreement Amendment”) with Revolving Lenders. The Revolving Credit Agreement Amendment provided for (i) the Revolving Lenders to temporarily forbear from exercising certain rights and remedies against the Borrowers in connection with anticipated financial covenant defaults under the Revolving Credit Agreement for the quarter ended December 31, 2018 and (ii) a temporary reduction in the minimum liquidity requirement under the Revolving Credit Agreement. The forbearance agreement was through January 31, 2019.

As of December 2018, we wrote off $4.2 million of deferred financing costs relating to the reduction in the borrowing capacity under our Revolving Credit Facility.

On January 31, 2019, we entered into the Forbearance Agreement and Second Amendment to Revolving Credit Agreement (the “Revolving Credit Agreement Second Amendment”) with the Revolving Lenders. The Revolving Credit Agreement Second Amendment provided for the Revolving Lenders to temporarily forbear from exercising certain rights and remedies against the Borrowers in connection with financial covenant defaults under the Revolving Credit Agreement, as amended by Revolving Credit Agreement Amendment and certain other potential defaults that may occur during the forbearance period. The forbearance agreement was through March 1, 2019.

On February 28, 2019, we entered into the Forbearance Agreement and Third Amendment to Revolving Credit Agreement (the “Revolving Credit Agreement Third Amendment”) with the Revolving Lenders. The Revolving Credit Agreement Third Amendment provided for the Revolving Lenders to temporarily forbear from exercising certain rights and remedies against the Borrowers in connection with financial covenant defaults under the Revolving Credit Agreement Second Amendment and certain other potential defaults that may occur during the forbearance period. The forbearance agreement was through March 28, 2019. On March 15, 2019, the noteholders under the Note Purchase Agreement exercised their option in the intercreditor agreement to purchase our indebtedness and assume the rights and obligations of the lenders under the Revolving Credit Agreement.

As of December 31, 2018, we had drawn $33.0 million and had $11.2 million of outstanding letters of credits. As of September 30, 2019, we had $48.5 million outstanding and all letters of credit were fully drawn upon.

On April 12, 2017, we entered into a $40.0 million second lien senior secured term loan facility among Emerge, as parent guarantor, and all of its subsidiaries, as borrowers (the “Borrowers”), and U.S. Bank National Association as disbursing agent and collateral agent (the “Prior Second Lien Term Loan Agreement”).

2023. Proceeds of the sale of the notes under the Note Purchase Agreement were used (i) to fully pay off the Partnership’s Prior Second Lien Term Loan Agreement, (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 Note Purchase Agreement contains various covenants and restrictive provisions and also requires the maintenance of certain financial covenants as follows:

The notes under the Note Purchase Agreement bear interest at 11% per annum until December 31, 2018, and ranging from 10.00% per annum to 12.00% per annum thereafter, depending on our leverage ratio. Following our default on certain financial covenants as of December 31, 2018, the interest rate increased to 13% on December 31, 2018 and 14% on April 1, 2019.

In lieu of paying cash for certain costs, we also issued 814,295 units to the noteholders under the Note Purchase Agreement in January 2018.

On December 31, 2018, we entered into the Forbearance Agreement and First Amendment to the Note Purchase Agreement (the “Note Purchase Agreement Amendment”) with HPS as notes agent and collateral agent, and the other noteholders party thereto. The Note Purchase Agreement Amendment provided for (i) the noteholders to temporarily forbear from exercising certain rights and remedies against the Borrowers in connection with anticipated financial covenant defaults under the Note Purchase Agreement for the quarter ended December 31, 2018 and (ii) a temporary reduction in the minimum liquidity requirement under the Note Purchase Agreement.

In connection with the Note Purchase Agreement Amendment, we performed a one-time fair value measurement of our Note Purchase Agreement under the guidance of ASC 470-50 - Debt. A portion of this note was deemed extinguished under this guidance at December 31, 2018. This portion represented 21% of our note held by a single noteholder. There was no accounting impact to the remaining 79% of the term note. The fair value of the Note Purchase Agreement was determined using Level 3 inputs. Our valuation model considered various inputs including estimation of market yield, credit worthiness, current trends, market conditions, and other relevant factors deemed material. The fair value of the Note Purchase Agreement was $196.3 million, and the 21% of the note extinguished was valued at $41.1 million. We recognized a $1.9 million loss on extinguishment of debt in accordance with ASC 470-50, which mainly represents the difference between the fair value and carrying value of debt, write-off of all remaining unamortized debt issuance costs, and unamortized original issuance discount.

On January 31, 2019, we entered into the Forbearance Agreement and Second Amendment to the Note Purchase Agreement (the “Note Purchase Agreement Second Amendment”) with HPS as notes agent and collateral agent, and the other noteholders party thereto. The Note Purchase Agreement Second Amendment provided for the noteholders to temporarily forbear from exercising certain rights and remedies against the Borrowers in connection with financial covenant defaults under the Note Purchase Agreement (as amended by the Note Purchase Agreement Amendment) and certain other potential defaults that may occur during the forbearance period. The forbearance agreement expired on March 1, 2019. We do not currently have a forbearance agreement under our Note Purchase Agreement, but any enforcement is stayed due to our Chapter 11 proceedings.

We were not in compliance with our Revolving Credit Facility and Note Purchase Agreement total leverage ratio and fixed charge coverage ratio covenants at December 31, 2018, March 31, 2019, and June 30, 2019.

In connection with the Chapter 11 Cases, on the DIP Closing Date, the Debtors entered into the DIP Facility. The DIP Facility is in an amount of up to $35 million (the “Commitment Amount”), and roll-up of obligations outstanding under the Revolving Credit Facility in an aggregate principal amount equal to the proceeds of the collateral received on and from the closing date of the DIP Facility. As of September 30, 2019, we had $15.0 million drawn under the Commitment Amount.

Interest on the DIP Facility will accrue at a rate per year equal to the LIBOR rate (with a floor of 2.00%) plus 8.00% or alternate base rate plus 7.00%. Following certain events of default under the DIP Facility, the lenders are charging default interest equal to an additional 2% on all obligations thereunder.

The Company is required to pay fees in relation to the DIP Facility, including the following:

The DIP Facility will mature on the earlier of: (i) six months after the DIP Closing Date; (ii) the date any Debtor enters into (or files a motion with the Bankruptcy Court or otherwise takes action to seek the Bankruptcy Court’s authorization of) any agreement for the sale or transfer of all or any material portion of the Debtors’ assets unless such agreement and any related orders provide for the indefeasible payment of the obligations under the DIP Facility on or prior to the closing of such proposed sale or transfer; (iii) the date which is the closing date of any sale or transfer of all or any material portion of the Debtors’ assets, other than sales or transfers of inventory in the ordinary course of business; (iv) the filing or support by any Debtor of a Chapter 11 plan that (x) does not provide for indefeasible payment in full of the obligations under the DIP Facility and (y) is not otherwise acceptable to the required lenders; (v) the effective date of Chapter 11 plan of reorganization or liquidation filed in any of the Chapter 11 Cases that is confirmed pursuant to an order entered by the Bankruptcy Court; (vi) 30 days after the entry of the interim order by the Bankruptcy Court, if the final order shall not have been entered by the Bankruptcy Court on or prior to such date; (vii) the date the Bankruptcy Court orders any Chapter 11 Case be converted to a case filed under Chapter 7 of the Bankruptcy Court or the dismissal of the Chapter 11 Case of any Debtor; (viii) the date of termination of the commitments under the DIP Facility and the acceleration of the loans (including the occurrence of an event of default or any default under the interim order or final order); or (ix) the termination of the restructuring support agreement by the Debtors or the consenting creditors under the restructuring support agreement.

The DIP Facility contains various covenants and restrictive provisions which also require the maintenance of certain financial and other related covenants such as the following:

In addition, the DIP Facility contains various milestone requirements related to the Chapter 11 case along with disclosure requirements which include, but not limited to:

Proceeds of the DIP Facility can be used by the Debtors to, among other things, fund the Debtors’ general business purposes, including working capital requirements during the pendency of the Chapter 11 Cases and to pay certain fees and expenses of professionals retained by the Debtors, in each case subject to certain limitations provided in the DIP Facility.

allow for the lenders to exercise rights and remedies, including but not limited to declaring outstanding principal, fees and interest thereunder immediately due and payable. In addition, due to these events of default, the lenders are charging default interest equal to an additional 2% on all obligations thereunder. The DIP Facility permits advances during an event of default, in the DIP Administrative Agent’s sole discretion. Additionally, we did not meet the milestone requirement for filing the Quarterly Report for the quarter ended June 30, 2019, which would also constitute an event of default under the DIP Facility.

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, 2018, 2017, and 2016.

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 lower accounts receivable balances in 2018 due to reduced sales during the fourth quarter of 2018, offset by higher prepaid expenses relating to our San Antonio plant, and higher inventory balances due to winter stock piles in Wisconsin. Due to cash constraints, we delayed payments to our vendors, did not make payments to certain vendors and did not make payments under certain contractual obligations. As of December 31, 2018, our long-term debt is classified as current due to non-compliance with certain financial covenants described in detail in Note 12 to our Consolidated Financial Statements.

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.

Cash flows used in operating activities in 2016 were significantly impacted by lower accounts receivable balances resulting from lower sales of sand in 2016, and a build-up of inventories in 2015 offset by higher prepaid and other current assets balances in 2016.

Cash flows used in investing activities increased during the year ended December 31, 2018, due to construction of the San Antonio plants. Cash flows used in investing activities during 2017 related to the asset acquisition of our San Antonio operations. We had significantly curtailed our capital expenditures to comply with our bank covenants that limited capital expenditures during 2018 and 2017.

Cash flows from investing activities in 2016 related to the proceeds from the sale of the Fuel business of $154.0 million in 2016.

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

In January 2018, we entered into the Revolving Credit Agreement and the Note Purchase Agreement described in Note 12 to our Consolidated Financial Statements. Proceeds of the sale of the notes under the 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.

In April 2017, we entered into a second lien term loan for $40 million in connection with our acquisition in San Antonio as described in Note 12 to our Consolidated Financial Statements. Proceeds of the new term credit facility were used to (i) pay down a portion of the existing revolving credit facility, (ii) fund the acquisition described in Note 2 (iii) pay fees and expenses incurred in connection with the new term credit facility and (iv) for general business purposes.

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, 2018.

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.

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.

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, 2018 were as follows:

In particular, subject to certain exceptions, under the Bankruptcy Code, the Debtors may assume, assign, or reject certain executory contracts and unexpired leases subject to the approval of the Bankruptcy Court and certain other conditions. Generally, the rejection of an executory contract or unexpired lease is treated as a pre-petition breach of such executory contract or unexpired lease and, subject to certain exceptions, relieves the Debtors of performing their future obligations under such executory contract or unexpired lease but entitles the contract counterparty or lessor to a pre-petition general unsecured claim for damages caused by such deemed breach. Counterparties to such rejected contracts or leases may assert claims against the applicable Debtor's estate for such damages. Generally, the assumption of an executory contract or unexpired lease requires the Debtors to cure existing monetary defaults under such executory contract or unexpired lease and provide adequate assurance of future performance. Accordingly, any description of an executory contract or unexpired lease with the Debtor in this Annual Report, including where applicable a quantification of our obligations under any such executory contract or unexpired lease with the Debtor is qualified by any overriding rejection rights we have under the Bankruptcy Code. Further, nothing herein is or shall be deemed an admission with respect to any claim amounts or

calculations arising from the rejection of any executory contract or unexpired lease and the Debtors expressly preserve all of their rights with respect thereto.

As of December 31, 2018, 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. As of September 30, 2019, all letters of credit were fully drawn upon.

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. 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:

Our mineral reserves are initially recognized at cost and are depleted using 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 by dividing the physical units of sand produced during the period by the total estimated mineral resources at the beginning of the period.

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 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.

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.

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.

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.

As of January 1, 2018, we adopted the new Accounting Standards Update ("ASU") 2014-09, Revenue from Contracts with Customers (Topic 606), and all the related amendments to all contracts using the full retrospective method. The adoption of Topic 606 had no impact on our revenue recognition practices or impact to our Consolidated Financial Statements but required additional disclosures.

We recognize revenue at a point in time when obligations under the terms of a contract with our customer are satisfied. This occurs with the transfer of control of our products to customers when products are shipped for direct sales to customers or when the product is picked up by a customer either at our plant location or transload location. Our contracts contain one performance obligation which is the delivery of sand to the customer at a point in time. Revenue is measured as the amount of consideration we expect to receive in exchange for transferring products. We recognize the cost for shipping as an expense in cost of sales when control over the product has transferred to the customer. Sales taxes collected concurrently with revenue-producing activities are excluded from revenue.

A limited number of our contracts have variable consideration, including shortfall fees and demurrage fees. For a limited number of customers, we sell under long-term, minimum purchase supply agreements. These agreements define, among other commitments, the volume of product that our customers must purchase, the volume of product that we must provide, and the price that we will charge for each product. The shortfall fees are billed when the customer does not meet the minimum purchases over a period of time defined in each contract. As we do not have the ability to predict the customer’s orders over the period, there are constraints around our ability to recognize the variability in consideration related to this condition. Demurrage fees are assessed to customers for not returning the railcar timely and according to the terms of the contract. Estimation of demurrage fees is also constrained as we cannot estimate when the customer will pick up the product from the railcar upon delivery. Revenue from customer contracts with variable considerations is recognized at the end of the defined period when collectability is certain.

Our payment terms vary by type and location of our customers. In most cases, the term between invoicing and the payment due date is 30 days. For certain customers, we require payment before the product is delivered.

New accounting guidance that has been recently issued is described in Note 2 - Significant Accounting Policies to our Consolidated Financial Statements in Part II, Item 8 of this Annual Report on Form 10-K.

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 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.

We are exposed to fluctuations in interest rates charged on our variable rate debt. As of December 31, 2018, we had $33.0 million of debt outstanding under the Revolving Credit Facility. A hypothetical increase or decrease in interest rates by 100 basis points would have changed the interest incurred on our variable rate debt by $0.2 million for the year ended December 31, 2018.

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 45% and 50% of our net accounts receivable at December 2018, and 2017, respectively. In March 2019 we sued one of our top three customers, EP Energy Corporation, for failure to purchase minimum contract volumes under a sand supply agreement with us. As a result, we no longer sell product to EP Energy Corporation. As of December 31, 2018, we have fully reserved our exposure and do not expect to have exposure on a go forward basis.

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

We have audited the accompanying consolidated balance sheets of Emerge Energy Services LP (the “Company”) as of December 31, 2018 and 2017, the related consolidated statements of operations, partners’ equity, and cash flows for each of the three years in the period ended December 31, 2018, 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, 2018 and 2017, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2018, 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, 2018, 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 October 18, 2019, expressed an adverse opinion thereon.

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 3 to the consolidated financial statements, the Company has suffered significant losses and negative cash flows from operations. The Company has negative working capital, liquidity challenges, covenant violations, is currently in default under its debt agreements and certain other contractual agreements and on July 15, 2019 the Company filed Chapter 11 bankruptcy. These factors, among others, raise substantial doubt about its ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 3. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

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 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 audits 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 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.

	December 31,
	2018			2017
ASSETS
Current assets:
Cash and cash equivalents	$	3,559		$	5,729
Trade and other receivables, net		16,355			56,951
Inventories		27,324			27,825
Prepaid expenses and other current assets		11,849			6,331
Total current assets		59,087			96,836

Property, plant and equipment, net		140,384			185,970
Intangible assets, net		6			1,664
Other assets, net		11,942			15,646
Total assets	$	211,419		$	300,116

LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable	$	23,023		$	18,819
Accrued liabilities		17,319			29,718
Current portion of long-term debt		227,462			—
Total current liabilities		267,804			48,537

Long-term debt, net of current portion		—			176,351
Obligation for business acquisition, net of current portion		4,083			5,013
Other long-term liabilities		11,546			21,106
Total liabilities		283,433			251,007

Commitments and contingencies (Note 14)
Partners’ equity:
General partner		—			—
Limited partner common units - 31,115,034 units and 30,174,940 units issued and outstanding as of December 31, 2018, and 2017, respectively		(72,014	)		49,109
Total partners’ equity		(72,014	)		49,109
Total liabilities and partners’ equity	$	211,419		$	300,116

	Year Ended December 31,
	2018			2017			2016
Revenues	$	313,590		$	364,302		$	128,399
Operating expenses:
Cost of goods sold (excluding depreciation, depletion and amortization)		257,922			304,279			173,907
Depreciation, depletion and amortization		19,633			21,899			19,126
Asset impairments		105,645			—			—
Selling, general and administrative expenses		26,769			26,796			20,951
Contract and project terminations		1,689			—			4,011
Total operating expenses		411,658			352,974			217,995
Operating income (loss)		(98,068	)		11,328			(89,596	)
Other expense (income):
Interest expense, net		30,993			19,171			21,339
Loss on extinguishment of debt		1,906			—			—
Other		(2,571	)		(4,207	)		2,471
Total other expense		30,328			14,964			23,810
Income (loss) from continuing operations before provision for income taxes		(128,396	)		(3,636	)		(113,406	)
Provision (benefit) for income taxes		147			71			(191	)
Net income (loss) from continuing operations		(128,543	)		(3,707	)		(113,215	)
Discontinued Operations
Income (loss) from discontinued operations, net of taxes		—			(3,125	)		8,746
Gain on sale of discontinued operations		—			—			31,699
Total income (loss) from discontinued operations, net of tax		—			(3,125	)		40,445
Net income (loss)	$	(128,543	)	$	(6,832	)	$	(72,770	)

Earnings (loss) per common unit (1)
Basic:
Earnings (loss) per common unit from continuing operations	$	(4.14	)	$	(0.12	)	$	(4.55	)
Earnings (loss) per common unit from discontinued operations		—			(0.11	)		1.63
Basic earnings (loss) per common unit (1)	$	(4.14	)	$	(0.23	)	$	(2.92	)
Diluted:
Earnings (loss) per common unit from continuing operations	$	(4.14	)	$	(0.12	)	$	(4.55	)
Earnings (loss) per common unit from discontinued operations		—			(0.11	)		1.63
Diluted earnings (loss) per common unit (1)	$	(4.14	)	$	(0.23	)	$	(2.92	)
Weighted average number of common units outstanding including participating securities (basic) (1)		31,037,266			30,132,480			24,870,258
Weighted average number of common units outstanding (diluted) (1)		31,037,266			30,132,480			24,870,258

(1) See Note 19.

	Limited Partner Common Units			General Partner (non-economic interest)		Total Partners’ Equity			Preferred Units
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			—
Net income (loss)		(128,543	)		—		(128,543	)		—
Equity-based compensation		1,507			—		1,507			—
Issuance of equity		5,974			—		5,974			—
Other		(61	)		—		(61	)		—
Balance at December 31, 2018	$	(72,014	)	$	—	$	(72,014	)	$	—

	Year Ended December 31,
	2018			2017			2016
Cash flows from operating activities:
Net income (loss)	$	(128,543	)	$	(6,832	)	$	(72,770	)
Adjustments to reconcile net income (loss) to net cash flows from operating activities:
Depreciation, depletion and amortization		19,633			21,899			21,480
Asset impairments		105,645			—			—
Equity-based compensation expense		1,507			1,423			719
Project and contract termination costs		1,689			—			4,008
Loss on extinguishment of debt		1,906			—			—
Unrealized (gain) loss on fair value of warrant		(2,530	)		(4,208	)		2,090
Write-down of escrow receivable		—			3,125			—
Provision for doubtful accounts		310			17			1,215
Loss (gain) on disposal of assets		619			79			635
Amortization of debt discount/premium and deferred financing costs		8,277			3,901			6,170
Non-capitalized cost of private placement		—			—			404
Write-down of inventory		4,694			—			5,394
Unrealized (gain) loss on derivative instruments		—			(227	)		224
Gain on sale of discontinued operations		—			—			(31,699	)
Other non-cash charges		122			113			117
Changes in operating assets and liabilities:
Accounts receivable		40,281			(31,865	)		(2,063	)
Inventories		(4,193	)		(10,368	)		9,052
Prepaid expenses and other current assets		(5,519	)		1,918			2,533
Accounts payable and accrued liabilities		(9,720	)		18,065			(4,910	)
Other assets		(323	)		857			10,075
Cash flows from operating activities		33,855			(2,103	)		(47,326	)

Cash flows from investing activities:
Purchases of property, plant and equipment		(78,555	)		(7,448	)		(13,523	)
Net proceeds from disposal of assets		1,188			211			82
Asset acquisition		—			(20,430	)		—
Proceeds from sale of discontinued operations, net		—			—			153,973
Collection of notes receivable		—			—			9
Cash flows from investing activities		(77,367	)		(27,667	)		140,541

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		49,014			356,262			320,726
Proceeds from second lien term notes		176,048			39,597			—
Repayment of line of credit borrowings		(159,714	)		(353,263	)		(482,089	)
Repayment of second lien term note		(5,375	)		—			—
Repayment of other long-term debt		(4,382	)		—			—
Payment of business acquisition obligation		(1,344	)		(2,802	)		(848	)
Payment of financing costs		(12,844	)		(4,158	)		(6,733	)
Other financing activities		(61	)		(141	)		(377	)
Cash flows from financing activities		41,342			35,495			(114,081	)

Cash and cash equivalents:
Net increase (decrease)		(2,170	)		5,725			(20,866	)
Balance at beginning of period		5,729			4			20,870
Balance at end of period	$	3,559		$	5,729		$	4

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 an 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.

On April 18, 2019, we entered into a Restructuring Support Agreement pursuant to which we have agreed to the principal terms of a proposed financial restructuring of the Partnership.

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 5 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.

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, 2018.

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.

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.

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.

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.

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.

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 5 – “Discontinued Operations” for further detail.

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 $327 thousand at December 31, 2018, and $17 thousand at December 31, 2017.

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.

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.

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.

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.

Management’s estimates of prices, volumes, recoverable proven and probable reserves and operating and capital costs are subject to certain risks and uncertainties which may affect the recoverability of our investments in property, plant and equipment. Although management has made its best estimate of these factors based on current conditions, it is reasonably possible that changes could occur in the near term, which could adversely affect management’s estimate of the net cash flows expected to be generated from our Wisconsin mines and plants. In management’s opinion, no impairment of long-lived assets existed at December 31, 2017 and 2016.

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.

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 $5.5 million and $7.2 million as of December 31, 2018, and 2017, respectively, and is included in “Other assets, net” on our Consolidated Balance Sheets. Pursuant to the adoption of ASU 842 on January 1, 2019, this balance will be included in the ROU operating assets, and will be reviewed for impairments, in accordance with FASB ASC 360, whenever events or changes in circumstances indicate that the related carrying amount may not be recoverable.

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.

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.

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.

In May 2014, the Financial Accounting Standards Board (“FASB”) issued ASU 2014-09, Revenue from Contracts with Customers, ASC 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. ASC 606 replaced most existing revenue recognition guidance in United States Generally Accepted Accounting Principles (“GAAP”) when it became effective for fiscal years beginning after December 15, 2017. ASC 606 permits the use of either the retrospective or cumulative effect transition method. We completed a review of contracts and their associated business terms and conditions and performed analysis on the impact of this standard to our contracts. We adopted the new standard on January 1, 2018, using the full retrospective method. Because accounting for revenue under contracts did not materially change for us under the new standard as explained below, prior period consolidated financial statements did not require adjustment.

Our sand products are sold to United States and Canada-based customers primarily in the energy industry. Demand for our product is impacted by the economic conditions related to the energy industry, particularly fluctuations in oil and gas prices. This affects the nature, amount, timing and uncertainty of our revenue. Changes in the price of oil and gas relative to other inflationary measures could make our products more or less affordable and therefore affect our sales. We also sell a small quantity of non-frac sand to customers outside the energy industry.

The following tables present our revenues disaggregated by nature of product for the year ended December 31, 2018, 2017, and 2016:

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

A limited number of our contracts have variable consideration, including shortfall fees and demurrage fees. For a limited number of customers, we sell under long-term, minimum purchase supply agreements. These agreements define, among other commitments, the volume of product that our customers must purchase, the volume of product that we must provide, and the price that we will charge for each product. The shortfall fees are billed when the customer does not meet the minimum purchases over a period of time defined in each contract. As we do not have the ability to predict the customer’s orders over the period, there are constraints around our ability to recognize the variability in consideration related to this condition. Demurrage fees are assessed to customers for not returning the railcar timely and according to the terms of the contract. Estimation of demurrage fees is also constrained as we cannot estimate when the customer will pick up the product from the railcar upon delivery. Shortfall fees and demurrage represent an immaterial amount of revenue historically. For the year ended December 31, 2018, $3.9 million of shortfall revenues were recognized on take-or-pay customer contracts. For these contracts we estimate our position quarterly using the most likely outcome method, including customer-provided forecasts and historical buying patterns, and we accrue for any asset or liability these arrangements may create. The effect of accruals for variable consideration on our consolidated financial statements is immaterial.

After an analysis of all of our long-term, minimum purchase supply agreements and a review of the standard terms of the purchase orders, we determined that there is no material change in the transaction price and amounts allocated to performance obligations, or the timing of satisfaction of performance obligations under ASC 606 compared to our accounting for these items in previous periods.

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.

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, 2018, and 2017, we had no accrued expenses related to environmental costs.

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 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 at the measurement date. 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 carry amounts of our Revolving Credit Facility approximates fair value because the underlying instrument includes a variable interest rate based on credit quality and first priority lien. The fair value of our Note Purchase Agreement was $196.3 million and was estimated using valuation models based on market information.

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 included in Other long-term liabilities on our Consolidated Balance sheets and 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 $2.5 million and $4.2 million during the year ended December 31, 2018, and 2017, respectively, and a loss of $2.1 million during the year ended December 31, 2016.

model considered various inputs including estimation of market yield, credit worthiness, current trends, market conditions, and other relevant factors deemed material. The fair value of the Note Purchase Agreement was $196.3 million, and the 21% of the note extinguished was valued at $41.1 million. We recognized a $1.9 million loss on extinguishment of debt in accordance with ASC 470-50, which mainly represents the difference between the fair value and carrying value of debt, write-off of all remaining unamortized debt issuance costs, and unamortized original issuance discount.

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, 2018. 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, 2018, and December 31, 2017, from such significant customers are set forth below:

The table shows the percent of revenue of our significant customers for our continuing operations for the years ended December 31, 2018, 2017 and 2016.

In March 2019, we sued one of our largest customers for failure to purchase minimum contract volumes under a sand supply agreement with us. We no longer sell product to this customer. As of December 31, 2018, we have fully reserved our exposure and do not expect to have exposure on a go forward basis.

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.

Although we own no long-term assets outside the United States, our Sand segment began selling product in Canada during 2013. We recognized $28.6 million, $32.0 million and $15.6 million of revenues in Canada for the years ended December 31, 2018, 2017, and 2016, respectively. All other sales have occurred in the United States.

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.

During the preparation of our 2018 consolidated financial statements, we identified an immaterial error in our previously issued financial statements relating to the accounting for deferred lease assets and deferred rent liabilities in accordance with ASC 840 - Leases. We incorrectly recorded consideration paid as a deferred lease asset instead of treating it as a reduction of the related deferred lease obligation. As a result, the deferred lease asset (within Other Assets, net) was overstated by $8.8 million as of December 31, 2017 and 2016 with an offsetting impact to other long-term liabilities. The impact on the income statement was not material, so the income statements were not revised. In connection with the error noted above, payments of $2.0 million that were reflected as financing activities in our financial statements for the nine months ended September 30, 2018 should have been included in operating activities. The classification has been corrected in the consolidated statement of cash flows for the year ended December 31, 2018 as an out-of-period adjustment. Management determined that these errors were not material to any prior periods, and the prior period balance sheets have been revised to correct this error. In addition, the current period impact, if not corrected prior to the issuance of the financial statements, would have resulted in a material misstatement. See further discussion in Item 9A.

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. In July 2018, the FASB issued ASU No. 2018-11, “Leases (Topic 842): Targeted Improvements”, which simplifies the implementation by allowing entities the option to instead apply the provisions of the new guidance at the effective date, without adjusting the comparative periods presented.

We lease railcars, office space, mining/processing equipment and other equipment. We evaluate our contracts to identify leases, which is generally if there is an identified asset and we have the right to direct the use of and obtain substantially all of the economic benefit from the use of the identified asset. We will adopt the new standard effective January 1, 2019, using the modified retrospective transition approach, and estimate a material increase of operating lease right-of-use (“ROU”) assets and liabilities, including any lease prepayments made and initial direct costs incurred on our Consolidated Balance Sheet.

With respect to the available practical expedients, we elected the primary package of expedients whereby we reassessed neither the existence, nor the classification nor the amount and treatment of initial direct costs of existing leases. We did not elect to use hindsight when considering judgments and estimates such as assessments of lessee options to extend or terminate a lease or purchase the underlying asset. For all asset classes, we elected to not recognize a ROU asset and lease liability for short-term leases. We elected the expedient to not separate the lease components from the non-lease components. We have implemented a lease accounting system and enhanced accounting systems and updated business processes and controls related to the new guidance for leases.

The Company will record initial right of use assets and related liabilities of approximately $129 million to $159 million on its consolidated balance sheet on January 1, 2019. The adoption of this standard will not materially impact our consolidated results of operations.

In August 2018, the FASB issued ASU 2018-15, Intangibles-Goodwill and Other-Internal-Use Software. The new guidance requires a customer in a cloud computing arrangement (i.e., hosting arrangement) that is a service contract to follow the internal-use software

guidance in ASC 350-40 to determine which implementation costs to capitalize as assets or expense as incurred. Capitalized implementation costs related to a hosting arrangement that is a service contract will be amortized over the term of the hosting arrangement, beginning when the module or component of the hosting arrangement is ready for its intended use. The update is effective for calendar-year public business entities in 2020. For all other calendar-year entities, it is effective for annual periods beginning in 2021 and interim periods in 2022. We adopted this ASU in March 2019. The adoption of this ASU did not have a material impact on our financial statements.

During 2018 and especially the fourth quarter of 2018, we experienced significant losses and negative cash flows from operations. We incurred a net loss of $128.5 million for the year ended December 31, 2018 and have $267.8 million in current liabilities as of December 31, 2018. We had negative working capital and, prior to filing our Chapter 11 Cases, we delayed payments to our vendors, did not make payments to certain vendors and payments under certain contractual obligations, and we are in default under our Revolving Credit Agreement, Note Purchase Agreement and certain other contractual obligations. On July 15, 2019, we filed for bankruptcy under Chapter 11 with the United States Bankruptcy Court for the District of Delaware. These factors, among others, raise substantial doubt about our ability to continue as a going concern. Our consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

We are in breach of certain financial covenants for the year ended December 31, 2018, the quarter ended March 31, 2019, the quarter ended June 30, 2019 and the DIP Facility, and if the Restructuring as contemplated by the RSA and the Plan is not consummated, we will likely not have sufficient liquidity to make all required interest and amortization payments under our Revolving Credit Agreement and the Note Purchase Agreement during future periods.

On April 18, 2019, we entered into a Restructuring Support Agreement (the “RSA”) with (i) each of our direct and indirect subsidiaries, and the direct and indirect owners of our general partner (the “Consenting Equity Holders”), (ii) HPS and certain of the lenders under the Revolving Credit Facility (the “Revolving Loan Lenders”), and (iii) HPS and certain holders of the Company’s Notes (the “Noteholders,”).

As set forth in the RSA, the parties to the RSA have agreed to the principal terms of a proposed financial restructuring (the “Transaction”) of the Partnership. For an In-Court Reorganization implemented in one or more cases filed under Title 11 of the United States Code (the “In-Court Reorganization”), the RSA provides, in pertinent part, that if the class of holders of General Unsecured Claims vote to accept the Chapter 11 plan, then the Consenting Noteholders have agreed to carve-out from their collateral and receipt of 100% of the New Common Units in us a settlement fund to be shared collectively by such claimholders and the existing equity holders in us consisting of the New Common Units.

The Debtors filed the Bankruptcy Petitions on July 15, 2019. We expect the Plan to become effective in November, 2019, at which point the Debtors would emerge from bankruptcy. The Debtors commenced solicitation for the Plan on September 13, 2019. While we anticipate substantially all of our prepetition indebtedness will be discharged upon emergence from Chapter 11 bankruptcy, there is no assurance that the effectiveness of the Plan will occur in November, 2019, or at all. The filing of the Bankruptcy Petitions constituted an event of default that accelerated the Partnership’s obligations under all of its outstanding debt instruments, resulting in the principal and interest due thereunder immediately due and payable. However, any efforts to enforce such payment obligations were automatically stayed as a result of the filing of the Chapter 11 Cases, and the creditors’ rights of enforcement in respect of the debt instruments were subject to the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. For more

information regarding the Plan and the Debtors’ Bankruptcy Petitions, see “Item 1. Business—Overview—Reorganization and Chapter 11 Proceedings.”

On September 11, 2019, the Bankruptcy Court entered the Order (I) Approving the Disclosure Statement, (II) Establishing the Voting Record Date, Voting Deadline and Other dates, (III) Approving Procedures for Soliciting, Receiving and Tabulating Votes on the Plan and for Filing objections to the Plan and (IV) Approving the Manner and Forms of Notice and Other Related Documents, (V) Approving Procedures for Assumption of Contracts and Leases and Form and Manner of Assumption Notice, and (VI) Granting Related Relief (the “Disclosure Statement Order”). Among other things, the Disclosure Statement Order approved the Disclosure Statement for the First Amended Joint Plan of Reorganization for Emerge Energy Services LP and its Affiliate Debtors Under Chapter 11 of the Bankruptcy Code (as may be amended from time to time, the “Disclosure Statement”). The Disclosure Statement Order also approved the Company’s solicitation procedures with respect to the Plan. Pursuant to the terms of the Plan, only (a) holders of claims arising from, under or in connection with the certain Note Purchase Agreement (the “Prepetition Notes Agreement”) by and among the Partnership, certain of the Partnership’s subsidiaries, HPS, in its capacity as administrative notes agent and collateral agent, and certain noteholders party thereto (such claims, the “Class 5 Prepetition Notes Claims”) and (b) holders of general unsecured claims (such claims, the “Class 6 General Unsecured Claims”) are entitled to vote to accept or reject the Plan. The Company commenced solicitation for the Plan on September 13, 2019 by distributing, among other things, the Plan, the Disclosure Statement, and ballots to vote to accept or reject the Plan to holders of Class 5 Prepetition Notes Claims and Class 6 General Unsecured Claims.

As further provided in the Plan and pursuant to the terms of the Plan, if and only if at least two-thirds (2/3) in dollar amount and more than one-half (1/2) in number of Class 6 General Unsecured Claims vote to accept the Plan, then each holder of equity interests in the Partnership (the “Class 9 Old Emerge LP Equity Interests”) shall receive, in full satisfaction, settlement, discharge and release of, and in exchange for, such allowed Class 9 Old Emerge LP Equity Interests, its pro rata share of new warrants contemplated under that certain new warrants agreement (the “New Warrants Agreement”)² representing five percent (5%) of new limited partnership interests in the Partnership, as reorganized pursuant to the Plan (the “New Limited Partnership Interests”), issued and outstanding on the effective date of the Plan, prior to dilution by equity issued in connection with the new management incentive plan. As further provided in the Plan and pursuant to the terms of the Plan, if less than two-thirds (2/3) in dollar amount or fewer than one-half (1/2) in number of Class 6 General Unsecured Claims vote to accept the Plan, Class 6 will have rejected the Plan, in which case the holders of Class 9 Old Emerge LP Equity Interests shall not receive any distribution or retain any property on account of such equity interests in the Partnership and such equity interests in the Partnership will be cancelled without further notice.

In addition, and as further provided in the Plan and pursuant to the terms of the Plan, if and only if at least two-thirds (2/3) in dollar amount and more than one-half (1/2) in number of Class 6 General Unsecured Claims vote to accept the Plan, then (a) each holder of an allowed Class 5 Prepetition Notes Claim shall receive in full satisfaction, settlement, discharge and release of, and in exchange for, such claim, its pro rata share of: (1) secured notes contemplated under that certain new second lien notes agreement (the “New Second Lien Notes”), if any; (2) ownership interests (“New Emerge GP Equity Interests”) in the new general partner of the Partnership, as reorganized pursuant to the Plan; (3) preferred interests (the “Preferred Interests”) in the Partnership, as reorganized pursuant to the Plan less any Preferred Interests issued to satisfy claims in connection with the DIP Facility (as defined below); and (4) ninety-five percent (95%) of the New Limited Partnership Interests issued and outstanding on the effective date of the Plan, prior to dilution by equity issued in connection with the new management incentive plan and any issuances pursuant to the New Warrants Agreement; and (b) each holder of an allowed Class 6 General Unsecured Claim shall receive, in full satisfaction, settlement, discharge and release of, and in exchange for, such allowed Class 6 General Unsecured Claim: its pro rata share of: (1) five percent (5%) of the New Limited Partnership Interests issued and outstanding on the effective date prior to dilution by the new management incentive plan and any issuances pursuant to the New Warrants Agreement; and (2) new warrants contemplated under the New Warrants Agreement representing ten percent (10%) of the New Limited Partnership Interests issued and outstanding on the effective date prior to dilution by the new management incentive plan. As further provided in the Plan and pursuant to the terms of the Plan, if less than two-thirds (2/3) in dollar amount or fewer than one-half (1/2) in number of Class 6 General Unsecured Claims vote to accept the Plan, Class 6 will have rejected the Plan, in which case (a) each holder of an allowed Class 5 Prepetition Notes Claims shall receive, in full satisfaction, settlement, discharge and release of, and in exchange for, such claim, its pro rata share of: (1) the New Second Lien

Notes, if any; (2) the New Emerge GP Equity Interests; (3) the Preferred Interests less any Preferred Interests issued to satisfy claims in connection with the DIP Facility; and (4) one hundred percent (100%) of the New Limited Partnership Interests issued and outstanding on the Effective Date prior to dilution by equity issued in connection with the new management incentive plan; and (b) Class 6 General Unsecured Claims will be discharged without further notice and each holder of a Class 6 General Unsecured Claim shall not receive any distribution or retain any property on account of such Class 6 General Unsecured Claim.

There are no assurances we will be successful in our efforts to reduce our obligations and report profitable operations or to continue as a going concern, in which event investors may lose their entire investment.

On May 11, 2018, we signed a 25 years lease for the mining rights to approximately 600 acres located in Kingfisher County, Oklahoma, about 60 miles northwest of Oklahoma City. We purchased 40 acres of land adjoining the leased acreage on which to construct wet and dry processing plants expected to have a capacity of 1.5 million tons per year. This facility will serve the Mid-Continent region. Construction of the wet and dry processing plants is temporarily suspended.

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.

The assets acquired have been included in our consolidated balance sheets, and are depreciated and depleted according to the policies described in Note 2 to our Consolidated Financial Statements.

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:

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

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:

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.

During the fourth quarter of 2018, we wrote down $4.69 million of our sand inventory. This write-down is attributed to rapidly declining market conditions and a significant decline in prices for northern white sand.

We recognized $18.3 million, $18.8 million, and $17.0 million of depreciation and depletion expense for the years ended December 31, 2018, 2017, and 2016, respectively. Of these amounts, depreciation and depletion expense for continuing operations totaled $18.3 million, $18.8 million, and $16.0 million, respectively.

We capitalize a portion of the interest on funds borrowed to finance the construction of our plants. During the twelve months ended December 31, 2018, we capitalized $2.4 million of interest for the construction of the San Antonio and Oklahoma facilities.

During the twelve months ended December 31, 2017, and 2016, we did not record any capitalized interest.

Our intangible assets consisted of the following at December 31, 2018, and 2017:

We recognized $1.3 million, $3.1 million, and $4.5 million of amortization expense for the years ended December 31, 2018, 2017, and 2016, respectively. Of these amounts, amortization expense for continuing operations totaled $1.3 million, $3.1 million, and $3.1 million for the years ended December 31, 2018, 2017, and 2016, respectively.

During the fourth quarter of 2018, we experienced a rapid decline in demand for northern white sand. As a result, we performed a quantitative analysis and recognized a $0.05 million impairment of intangible assets associated with our Wisconsin operations.

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

On April 12, 2017, 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 (“PNC Bank”), as administrative agent and collateral agent (the “agent”), and the lenders thereto. The amendment permitted the Partnership and the Borrowers to enter into a Prior Second Lien Term Loan Agreement, as defined below, 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.

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

As of December 2018, we wrote off $4.2 million of deferred financing costs relating to the reduction in the borrowing capacity under our Revolving Credit Facility.

At December 31, 2018, we had undrawn availability under the Revolving Credit Facility of $18.6 million, below the $20.0 million minimum availability required under our covenants, and our outstanding borrowings under the Revolving Credit Facility bore interest at a weighted-average rate of 8.7%. Following our default on certain financial covenants as of December 31, 2018, the base rate on all borrowings under the Revolving Credit Facility increased by 2%.

On December 31, 2018, we entered into the Forbearance Agreement and First Amendment to Second Amended and Restated Revolving Credit and Security Agreement (the “Revolving Credit Agreement Amendment”) with Revolving Lenders. The Revolving Credit Agreement Amendment provided for (i) the Revolving Lenders to temporarily forbear from exercising certain rights and remedies against the Borrowers in connection with anticipated financial covenant defaults under the Revolving Credit Agreement for the quarter ended December 31, 2018 and (ii) a temporary reduction in the minimum liquidity requirement under the Revolving Credit Agreement. The forbearance agreement was through January 31, 2019.

On February 28, 2019, we entered into the Forbearance Agreement and Third Amendment to Revolving Credit Agremeent (the “Revolving Credit Agreement Third Amendment”) with the Revolving Lenders. The Revolving Credit Agreement Third Amendment provided for the Revolving Lenders to temporarily forbear from exercising certain rights and remedies against the Borrowers in

connection with financial covenant defaults under the Revolving Credit Agreement Second Amendment and certain other potential defaults that may occur during the forbearance period. The forbearance agreement was through March 28, 2019.

On March 15, 2019, the noteholders under the Note Purchase Agreement exercised their option in the intercreditor agreement to purchase our indebtedness and assume the rights and obligations of the lenders under the Revolving Credit Agreement.

On April 12, 2017, we entered into a $40.0 million second lien senior secured term loan facility among Emerge Energy Services, LP as parent guarantor, and all of its subsidiaries, as borrowers (the “Borrowers”), and U.S. Bank National Association as disbursing agent and collateral agent (the “Prior Second Lien Term Loan Agreement”).

On January 5, 2018, the Partnership entered into a $215.0 million second lien note purchase agreement with HPS as notes agent and collateral agent (the “Note Purchase Agreement”). The notes issued under the Note Purchase Agreement will mature on January 5, 2023. Proceeds of the sale of the notes under the Note Purchase Agreement were used (i) to fully pay off the Partnership’s Prior Second Lien Term Loan Agreement, (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 Note Purchase Agreement contains various covenants and restrictive provisions and also requires the maintenance of certain financial covenants as follows:

In lieu of paying cash for certain costs, we also issued 814,295 units valued at $6.0 million to the noteholders under the Note Purchase Agreement in January 2018.

50, which mainly represents the difference between the fair value and carrying value of debt, write-off of all remaining unamortized debt issuance costs, and unamortized original issuance discount.

In connection with the Chapter 11 Cases, on the DIP Closing Date, the Debtors entered into the DIP Facility. The DIP Facility is in an amount of up to $35 million (the “Commitment Amount”), and roll-up of obligations outstanding under the Revolving Credit Facility in aggregate principal amount equal to the proceeds of the collateral received on and from the closing date of the DIP Facility. As of September 30, 2019, we had $15.0 million drawn under the Commitment Amount.

The Company is required to pay fees in relation to the DIP Facility, including the following:

The DIP Facility contains various covenants and restrictive provisions which also require the maintenance of certain financial and other related covenants such as the following:

In addition, the DIP Facility contains various milestone requirements related to the Chapter 11 Cases along with disclosure requirements which include, but not limited to:

The Debtors have exceeded the Permitted Variance with respect to net cash flow for the week of August 26, 2019 and September 2, 2019 and the bi-weekly period ending August 30, 2019 and have breached milestone requirements in the DIP Facility related to the filing of the Annual Report and the Quarterly Report for the quarter ended March 31, 2019, both constituting events of default that allow for the lenders to exercise rights and remedies, including but not limited to declaring outstanding principal, fees and interest thereunder immediately due and payable. In addition, due to these events of default, the lenders are charging default interest equal to an additional 2% of all obligations thereunder. The DIP Facility permits advances during an event of default, in the DIP Administrative Agent’s sole discretion. Additionally, we did not meet the milestone requirement for filing the Quarterly Report for the quarter ended June 30, 2019, which would also constitute an event of default under the DIP Facility.

The following table presents the minimum contractual obligations for contractual commitments as of December 31, 2018.

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, 2018, 2017, and 2016, totaled $38.8 million, $37.4 million and $40.7 million, respectively.

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.

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, 2018, we recorded $1.0 million for volume commitment shortfalls. For December 31, 2017, we recorded $0.4 million for volume commitment shortfalls. For the year ended December 31, 2016, we recorded $1.4 million for volume commitment shortfalls at one of our transload facilities.

As of December 31, 2018, 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. As of September 30, 2019, all letters of credit were fully drawn upon.

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, and we expense legal costs related to claims and litigation in the period incurred. We had recognized no liabilities as of December 31, 2018, and 2017, 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.

In June 2018, an employee of Emerge was fatally injured at our San Antonio mine. MSHA investigated the incident and issued three citations, which Emerge is contesting. In addition, the employee’s family has filed a lawsuit against Emerge in the 45^th Judicial in Bexar County, Texas on May 6, 2019. The lawsuit is being defended by Emerge’s workman compensation insurer; however, there can be no assurance that our liability insurance will cover any or all costs related to the incident, which could have a material adverse effect on our financial position, liquidity or results of operations. Currently, the lawsuit stayed due to Emerge’s Chapter 11 proceedings, but Emerge intends to defend vigorously.

While current uninsured litigation matters are not expected to have a material adverse effect on our financial position, liquidity or results of operations, we are still assessing our exposure and there can be no assurance that our liability insurance will cover any or all costs, which could have a material adverse effect on our financial position, liquidity or results of operations.

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, 2018, and 2017. 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.

In December 2015, we gained access to a reserve base in Jackson County, Wisconsin through a business arrangement with a contracted customer. The assets acquired included certain owned and leased land, sand deposit leases and related prepaid royalties, and transferable mining and reclamation permits. In consideration for the assets, we amended and restated the existing supply agreement between the parties and entered into a new sand purchase option agreement that provided the customer with a market-based discount on sand purchased from us. Under the agreements, we have the option to supply the contracted tons from our existing footprint of northern white sand operations or construct a new sand mine and dry plant in Jackson County, Wisconsin. Due to changing market conditions and changing preferences of customer demand, we determined that these projects were no longer economically viable and decided to terminate the land owner agreements and the mine permits. We recorded a $1.9 million charge to earnings to write off the related prepaid royalties in 2018. As we terminated our permits for these properties, we will not owe any future royalty payments related to these properties.

Management committed to a plan to discontinue the development of sand processing facilities in Independence, Wisconsin and other small projects in Ohio and Missouri 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 12 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:

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

The Company follows ASC 850, Related Party Disclosures, for the identification of related parties and disclosure of related party transactions. In 2017, Mr. Paul Shearer, the son of our President and Chief Executive Officer, was hired as the Director of Business Relations and he currently serves as the Director of Sales and Marketing. During the year ended December 31, 2018, we paid Paul Shearer $194 thousand in total compensation, including base salary, bonus, company contributions under our 401(k) plan and contributions to his health savings account.

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. The administrative services agreement remains 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. 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 up until his termination in May 2019 and the Services Agreement was terminated.

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 67-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, 2018, the unpaid liability for distribution equivalent rights totaled $0.8 million.

In 2018, we granted 301,561 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 years.

The following table summarizes awards granted during the year ended December 31, 2018.

For the years ended December 31, 2018, 2017, and 2016, we recorded non-cash compensation expense relating to equity-based compensation of $1.5 million, $1.4 million, and $0.7 million, respectively, in selling, general and administrative expenses. Non-cash equity-based compensation expense for continuing operations was $0.4 million for the year ended December 31, 2016.

As of December 31, 2018, the unrecognized compensation expense related to the grants discussed above amounted to $1.1 million to be recognized over a weighted average of 1.3 years. As previously disclosed, a restructuring could result in a substantial dilution or elimination of the outstanding awards.

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:

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.

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 year ended December 31, 2016 was $19 thousand.

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 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, 2018, 2017, and 2016.

	Year Ended December 31,
	2018			2017			2016

	($ in thousands, except per unit data)
Net income (loss) from continuing operations	$	(128,543	)	$	(3,707	)	$	(113,215	)
Net income (loss) from discontinued operations		—			(3,125	)		40,445
Net Income (loss)	$	(128,543	)	$	(6,832	)	$	(72,770	)

Weighted average common units outstanding		31,037,266			30,132,480			24,870,258
Weighted average units deemed participating securities		—			—			—
Weighted average number of common units outstanding including participating securities (basic)		31,037,266			30,132,480			24,870,258
Weighted average potentially dilutive units outstanding		—			—			—
Weighted average number of common units outstanding (diluted)		31,037,266			30,132,480			24,870,258

Basic earnings (loss) per unit:
Earnings (loss) per common unit from continuing operations	$	(4.14	)	$	(0.12	)	$	(4.55	)
Earnings (loss) per common unit from discontinued operations		—			(0.11	)		1.63
Basic earnings (loss) per common unit	$	(4.14	)	$	(0.23	)	$	(2.92	)

Diluted earnings (loss) per unit:
Earnings (loss) per common unit from continuing operations	$	(4.14	)	$	(0.12	)	$	(4.55	)
Earnings (loss) per common unit from discontinued operations		—			(0.11	)		1.63
Diluted earnings (loss) per common unit	$	(4.14	)	$	(0.23	)	$	(2.92	)

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.

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.

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.

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 $2.5 million and $4.2 million during the year ended December 31, 2018, and 2017, respectively, 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:

The effect of derivative instruments, none of which has been designated for hedge accounting, on our Consolidated Statements of Operations was as follows:

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. Effective January 1, 2019, the employer match increased to 6%. 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 $0.8 million, $0.4 million, and $0.3 million for the years ended December 31, 2018, 2017, and 2016, respectively. We classified $118 thousand to income (loss) from discontinued operations, net of taxes for the twelve months ended December 31, 2016.

The following supplemental disclosures may assist in the understanding of our Consolidated Statements of Cash Flows:

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 (the “Exchange Act”). Based on that evaluation, our management, including our Chief Executive Officer and our Chief Financial Officer, had concluded that the design and operation of our disclosure controls and procedures were not effective as of the end of the period covered by this report due to a material weakness in internal control over financial reporting relating to non-routine and/or complex transactions, as described below.

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:

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, 2018, and has concluded that such internal control over financial reporting was not 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 (“COSO”) in the Internal Control - Integrated Framework (2013). During our assessment of the effectiveness of internal control over financial reporting as of December 31, 2018, we identified the following material weakness:

Ineffective controls in accounting for non-routine/complex transactions: Our control regarding non-routine and/or complex transactions was not effective. As a result, we failed to follow proper accounting treatment specific to certain debt transactions related to ASC 470, Debt and deferred lease assets and liabilities related to ASC 840, Leases. This material weakness resulted in adjustments prior to the issuance of the financial statements that, if not corrected, would have resulted in a material misstatement of the financial statements.

Remediation of the Material Weakness in Internal Control over Financial Reporting

In response to the identified material weakness, we have redesigned our controls and expect, when executed, these improvements will remediate this material weakness. Until the remediation efforts are fully implemented and operating for a sufficient period of time, the material weakness may continue to exist.

The effectiveness of our internal control over financial reporting as of December 31, 2018, 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.

There were no changes in internal control over financial reporting during the quarter ended December 31, 2018, (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.

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

We have audited Emerge Energy LP’s (the “Company’s”) internal control over financial reporting as of December 31, 2018, 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 did not maintain, in all material respects, effective internal control over financial reporting as of December 31, 2018, based on the COSO criteria.

We do not express an opinion or any other form of assurance on management’s statements referring to any corrective actions taken by the Company after the date of management’s assessment.

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 and subsidiaries as of December 31, 2018 and 2017, the related consolidated statements of operations, partners’ equity, and cash flows for each of the three years in the period ended December 31, 2018, and the related notes (collectively referred to as “the financial statements”)” and our report dated October 18, 2019 expressed an unqualified opinion thereon.

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.

A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company’s annual or interim financial statements will not be prevented or detected on a timely basis. A material weakness regarding management’s failure to design and maintain controls over non-routine/complex transactions has been identified and described in management’s assessment. This material weaknesses was considered in determining the nature, timing, and extent of audit tests applied in our audit of the 2018 financial statements.

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.

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, three 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 we were on December 31, 2018, 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 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.

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 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 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 served as our Chief Financial Officer of our general partner from February 2016 to June 2019. 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 served as Vice President and as a member of the board of directors of our general partner from April 2012 to June 2019. 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 served as Chief Accounting Officer of our general partner from February 2016 to June 2019. 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 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 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 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 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 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 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. 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 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.

Eugene Davis was appointed as an independent member of our board of directors since January 2019. He is currently the Chairman and Chief Executive Officer of PIRINATE Consulting Group, LLC, or PIRINATE, a privately held consulting firm specializing in turnaround management, merger and acquisition consulting, and hostile and friendly takeovers, proxy contests, and strategic planning advisory services for domestic and international public and private business entities. Since forming PIRINATE in 1997, Mr. Davis has advised, managed, sold, liquidated and served as a chief executive officer, chief restructuring officer, director, committee chairman or chairman of a number of businesses operating in diverse sectors. From 1990 to 1997, Mr. Davis served as President, Vice Chairman, and Director of Emerson Radio Corporation and from 1996 to 1997 he served as Chief Executive Officer and Vice Chairman of Sport Supply Group, Inc. He began his career as an attorney and international negotiator with Exxon Corporation and Standard Oil Company (Indiana) and was in private practice from 1984 to 1998. Mr. Davis serves as chairman of the board for Parker Drilling and Verso Corporation. In addition, Mr. Davis serves as a director of Sanchez Energy and Montage Resources Corp., as well as certain non-SEC reporting companies. Mr. Davis was previously a director of the following public companies: Atlas Air Worldwide Holdings, Inc., Atlas Iron Limited, The Cash Store Financial Services, Inc., Dex One Corp., Global Power Equipment Group, Inc., Goodrich Petroleum Corp., Great Elm Capital Corporation, GSI Group, Inc., Hercules Offshore, Inc., HRG, Knology, Inc., SeraCare Life Sciences, Inc., Spansion, Inc., Spectrum, Titan Energy, LLC and U.S. Concrete, Inc. Mr. Davis’ prior experience also includes having served on the board of directors of each of ALST Casino Holdco, LLC and Trump Entertainment Resorts, Inc. Mr. Davis holds a bachelor’s degree from Columbia College, a master of international affairs degree (MIA) in international law and organization from the School of International Affairs of Columbia University, and a Juris Doctorate from Columbia University School of Law.

Bill Transier was appointed as an independent member of our board of directors since April 2019. Mr. Transier currently serves as the chief executive officer of Transier Advisors, LLC, an independent advisory firm providing services to energy companies facing stressed operational situations, turnaround, restructuring or in need of interim executive leadership. He also currently serves as an independent director and chairman of the board for Helix Energy Solutions Group. Mr. Transier has been a member of the Helix board of directors since October 2000 and served as the lead independent director from March 2016 to July 2017 when he was appointed as chairman of the board. Mr. Transier served as a member of the board of directors of CHC Group Ltd. from May 2016 to July 2017. He was also a member of the board of directors of Paragon Offshore Plc. from August 2014 to July 2017. From December 2006 to December 2012, Mr. Transier served as a member of the board of directors of Cal Dive International, Inc., a publicly traded company that was formerly a subsidiary of Helix where he served as lead director from May 2009 to December 2012. Mr. Transier was co-founder of Endeavour International Corporation, an international oil and gas exploration and production company. He served as non-executive chairman of Endeavour’s board of directors from December 2014 until November 2015. Mr. Transier also served as chairman, chief executive officer and president of Endeavor from September 2006 to December 2014 and as co-chief executive officer from formation in February 2004 through September 2006. Mr. Transier served as executive vice president and chief financial officer of Ocean Energy, Inc. from March 1999 to April 2003 and prior to that, he served in various positions of increasing responsibility with Seagull Energy Corporation. Before his tenure with Seagull, Mr. Transier served in various roles including partner in the audit department and head of the Global Energy practice of KPMG LLP from June 1986 to April 1996. Mr. Transier earned his B.B.A. in accounting from the University of Texas, holds an MBA from Regis University and has a graduate degree in theological studies from Dallas Baptist University.

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.

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.

The board of directors of our general partner has established an audit committee (the “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 registered public accounting firm, to engage and resolve disputes with our independent registered public accounting firm, 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 registered public accounting firm, 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. 1301 (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.

Pursuant to the terms of the RSA, the board of directors of our general partner established a special restructuring committee (the “Committee”) in April 2018 and delegated to the Committee the authority to exercise the powers of the board with respect to the matters contemplated by the RSA (and the board relinquished all such powers delegated to the Committee), including implementing the terms of the Transaction, overseeing discussions with key stakeholders, managing day-to-day cash management and any other actions that the Committee determines, in good faith, are necessary or desirable in order to carry out its mandate. The Committee also oversees the company’s Chief Restructuring Officer, who is responsible for, among other matters, directing our collections, disbursement, treasury, liquidity and reporting obligations, managing financial and operational reporting processes, overseeing and approving expenditures and cash payments, development of business plans and financial models, and other services and activities as directed by the Committee. Messrs. Davis and Transier serve as the members of the Committee.

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.

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.

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, 2018, 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, 2018 and October 26, 2018. Ms. Deibert reported the withholding and the grant in Forms 4 filed on February 28, 2018 and December 18, 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, 2018. Messrs. Clark, Gottfredson, Jones and Kelly each reported the grant in a Form 4 filed on June 1, 2018.

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 2018 fiscal year, who were:

Pursuant to the execution of the RSA, Mr. Bonham was terminated from his position as a Vice President of our general partner effective May 17, 2019, but he still serves as a member of the board of directors of our general partner. In addition, on June 6, 2019, the employment of each of Mses. Deibert and Kurani was terminated.

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:

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:

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.

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 $525,000 to $551,250 effective January 1, 2018.

In December 2017, the board of directors of our general partner approved base salary increases for each of our other 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.

The following table sets forth our named executive officers’ 2018 annual base salaries. The actual base salaries paid to our named executive officers during 2018 are set forth in the “Summary Compensation Table” below:

In February 2019, the board of directors of our general partner approved base salary increases for each of our named executive officers of 5.5% (or 7% with respect to Ms. Kurani), effective January 1, 2019. 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. As mentioned above, the employment of each of Mr. Bonham and Mses. Deibert and Kurani since has been terminated.

In addition to base salaries, our executives are eligible to receive annual incentive bonuses. For 2018, annual incentive bonuses were targeted at the percentage of each executive’s annual base salary shown below.

For 2018, 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 2018 annual incentive bonus plan.

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.

The Adjusted EBITDA of $35.7 million achieved by Emerge in 2018 did not result in an annual incentive bonus payout for any of the named executive officers for 2018.

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.

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.

Pursuant to the terms of Mr. Shearer’s employment letter agreement with our general partner, in December 2018, we granted Mr. Shearer a phantom unit award covering 112,961 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, 2018, 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 2018, we granted Mses. Deibert and Kurani phantom unit awards covering 30,000 phantom units and 16,000 phantom units, respectively. The awards were scheduled to vest with respect to 50% of the units subject thereto on each of the first and second anniversaries of January 1, 2019, 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 would have vested. In connection with their terminations of employment in June 2019, Mses. Debiert and Kurani’s awards were subject to pro-rated accelerated vesting with the remainder forfeited.

In 2018, 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 did not offer Mr. Bonham severance benefits because of his association with Insight Equity.

As mentioned above, the employment of each of Mr. Bonham and Mses. Deibert and Kurani terminated in 2019. In connection with these terminations, Ms. Deibert received a mutually agreed upon severance payment equal to six months’ salary and Ms. Kurani received a mutually agreed upon severance payment equal to three months’ salary. Mr. Bonham did not receive any severance payment.

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 did 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. Mr. Shearer is entitled to receive a monthly automobile allowance equal to $1,917.

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.

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.

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.

Name and Principal Position	Salary ($)		Bonus ($)		Common Unit Awards ($)(1)		Non-Equity Incentive Plan Compensation ($)		All Other Compensation ($)(2)		Total ($)
Rick Shearer
Chief Executive Officer
2018		550,240		—		243,996		—		51,368		845,604
2017		525,000		—		787,498		891,595		9,794		2,213,887
2016		510,961		50,000		787,495		—		15,800		1,364,256
Deborah Deibert
Chief Financial Officer
2018		308,143		—		46,200		—		26,118		380,461
2017		293,471		—		166,175		312,069		12,762		784,477
2016		273,654		46,666		45,920		—		9,983		376,223
Warren Bonham
Vice President
2018		231,102		—		—		—		3,677		234,779
2017		220,093		—		—		187,232		2,904		410,229
2016		210,000		—		—		51,644		3,130		264,774
Nadya Kurani
Chief Accounting Officer
2018		195,463		—		24,640		—		17,467		237,570
2017		180,872		—		83,088		154,124		9,084		427,168
2016		160,385		27,500		22,960		—		7,194		218,039

The following table sets forth information regarding grants of plan-based awards made to our named executive officers during the year ended December 31, 2018:

For 2018, our general partner is a party to employment letters with Mr. Shearer and Mses. Deibert and Kurani, each of which is described below. We never 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 2018, we granted to Mr. Shearer the 2018 Award, which will vest in 50% installments on each of November 1, 2019, and November 1, 2020, 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. Under the Deibert Letter, Ms. Deibert was 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 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.

Effective December 7, 2018, we again amended the Deibert Letter (as amended, the “Amended Deibert Letter”) to further 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 initial annual salary was $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. The Kurani Letter is no longer effective.

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.

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, 2018:

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)		—		—		13,623		20,979
	12/29/2017 (4)		48,195		74,220		—		—
	12/14//2018 (4)		112,961		173,960		—		—
Deborah Deibert	1/1/2017 (5)		3,750		5,775		—		—
	12/29/2017 (5)		10,000		15,400		—		—
	12/31/2018 (5)		30,000		46,200		—		—
Warren Bonham	5/4/2013 (6)		—		—		82,974		873,716
Nadya Kurani	1/1/2017 (5)		1,875		2,888		—		—
	12/29/2017 (5)		5,000		7,700		—		—
	12/14/2018 (5)		16,000		24,640		—		—

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 2018:

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 60 days after the termination date.

Deborah Deibert. The Amended Deibert Letter provided that if Ms. Deibert’s employment was 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 would have been entitled to receive an amount equal to 12 months of her then-current annual base salary, payable in a cash lump sum amount on the 60th day following her termination date. In connection with the termination of her employment in June 2019, Ms. Deibert received a mutually agreed upon payment equal to six months of her base salary.

Warren Bonham. Except with respect to his phantom unit awards (described below), Mr. Bonham was not eligible to receive any severance or change in control benefits.

Nadya Kurani. The Kurani Letter provided 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 would have been 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. In connection with the termination of her employment in June 2019, Ms. Kurani received a mutually agreed upon payment equal to three months of her base salary.

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). In connection with their terminations of employment in June 2019, Mses. Deibert and Kurani’s awards were subject to pro-rated accelerated vesting with the remainder forfeited.

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, 2018, and, where relevant, that a change in control occurred on December 31, 2018. 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.

As described above, the employment of each of Mr. Bonham and Mses. Deibert and Kurani was terminated in 2019. In connection with these terminations, Ms. Deibert received a severance payment equal to six months’ salary and Ms. Kurani received a severance payment equal to three months’ salary. Mr. Bonham did not receive any severance payments. Also in connection with their terminations, Mses. Deibert and Kurani’s awards were subject to pro-rated accelerated vesting with the remainder forfeited; the phantom unit award held by Mr. Bonham forfeited in full in connection with his termination of employment.

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		1,102,500		—		1,102,500		1,102,500
Phantom Unit Acceleration		—		269,159		57,509		269,159
Total		1,102,500		269,159		1,160,009		1,371,659
Deborah Deibert
Cash Severance		—		—		308,708		308,708
Phantom Unit Acceleration		—		67,375		10,693		67,375
Total		—		67,375		319,401		376,083
Warren Bonham
Cash Severance		—		—		—		—
Phantom Unit Acceleration		—		873,716		—		873,716
Total		—		873,716		—		873,716
Nadya Kurani
Cash Severance		—		—		98,011		98,011
Phantom Unit Acceleration		—		35,228		1,532		35,228
Total		—		35,228		99,543		133,239

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.

Based on this information, for 2018, the estimated ratio of our CEO’s annual total compensation was 17 times that of the median of the annual total compensation of all of our employees.

We determined that, as of December 31, 2018, our employee population consisted of 279 employees, including full-time, part-time and temporary employees.

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 2018 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 2018.

With respect to the annual total compensation of the median employee, we identified and calculated the elements of such employee’s compensation for 2018 in accordance with the requirements of Item 402(c)(2)(x) of Regulation S-K, resulting in annual total compensation of $50,864.

Effective January 1, 2018, the board of directors of our general partner adopted the amended and restated 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.

Under the Director Plan, each eligible director is entitled to receive an annual cash retainer of $52,500. In addition, each committee chairperson receives a $10,500 annual cash retainer and each non-chair committee member receives a $2,625 annual cash retainer. Annual retainers are paid in cash quarterly in arrears and are pro-rated to reflect any partial year of service.

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 $78,750 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 $78,750 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. Due to the current restructuring efforts, the 2019 grant is currently under review and has not yet occurred.

In 2019, each of Eugene I. Davis and William L. Transier was appointed to the board of our general partner. In connection with their appointments, our general partner and each director entered into a letter agreement that provides the director will receive an annual retainer of $360,000, paid in equal monthly installments in advance, and the remainder of which will be payable to the director in a lump sum upon a termination of his service by the Company without cause, subject to his execution and non-revocation of a release of claims. In such an event, the Company also has agreed to execute a general release of claims against the applicable director.

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 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.

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.

The following table sets forth certain information regarding the beneficial ownership of units as of September 30, 2019, (the “Ownership Reference Date”) by:

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 31,185,729 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.

The following table summarizes certain information regarding our equity compensation plans, including our LTIP, as of December 31, 2018. Our LTIP allows for awards of options, phantom units, restricted units, unit awards, other unit awards and unit appreciation rights.

Ownership Interests of Certain Executive Officers and Directors of Our General Partner

Insight Equity owns 7,168,545 common units representing a 23% 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.

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.

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.

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 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”.

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 2018 and 2017, including out-of-pocket expenses billed.

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):

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.

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.

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.

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)

Title of Each Class		Trading Symbol (s)		Name of Each Exchange On Which Registered
Common Units Representing Limited Partner Interests		EMESZ		OTC

		Page
	PART I

Item 1.	Business	1

Item 1A.	Risk Factors	21

Item 1B.	Unresolved Staff Comments	49

Item 2.	Properties	49

Item 3.	Legal Proceedings	49

Item 4.	Mine Safety Disclosures	50

	PART II

Item 5.	Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	51

Item 6.	Selected Financial Data	52

Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	59

Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	80

Item 8.	Financial Statements and Supplementary Data	81

Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	117

Item 9A.	Controls and Procedures	117

Item 9B.	Other Information	120

	PART III

Item 10.	Directors, Executive Officers and Corporate Governance	120

Item 11.	Compensation Discussion and Analysis	127

Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	139

Item 13.	Certain Relationships and Related Transactions, and Director Independence	141

Item 14.	Principal Accounting Fees and Services	143

	PART IV

Item 15.	Exhibits and Financial Statement Schedules	144

Item 16.	Form 10-K Summary	144

Wet Plant Location	Proven Recoverable Reserves (Millions of Tons) (1)		Lease Expiration Date (2)	Plant Capacity (Thousands of Tons)		2018 Production (Thousands of Tons)
San Antonio, TX (3)		39.3	N/A		4,500		221
Kosse, TX		21.5	N/A		1,600		535
Auburn, WI		15.5	March 2036		2,000		1,194
Church Road, WI		5.3	N/A		1,200		577
FLS Mine, WI		8.8	July 2037		1,400		1,196
LP Mine, WI		3.3	March 2038		1,200		514
Thompson Hills, WI		36.8	December 2037		1,600		1,110
Kingfisher, Oklahoma (5)		24.7	May 2043		—		—

Dry Plant Location	On-site Railcar Storage Capacity (4)	Annual Plant Capacity (Thousands of Tons)		2018 Production Volumes (Thousands of Tons)
San Antonio, TX	10 cars		4,000		638
Kosse, TX	N/A		600		383
Arland, WI	N/A		2,500		1,075
Barron, WI	650 cars		2,400		1,577
New Auburn, WI	420 cars		1,400		1,017
Kingfisher, Oklahoma (5)	N/A		—		—

Transload Location by Basin	Transload Sites as of December 31, 2018		Transload Sites Capable of Receiving Unit Trains		2018 Volume Sold (Thousands of Tons)
Bakken Shale		2		2		159
Eagle Ford Shale		1		1		316
Haynesville Shale		1		1		24
Marcellus / Utica Shales		3		1		105
Uintah Shale		1		1		9
Permian Basin		1		1		365
Western Canadian Sedimentary Basin		4		1		319
Total tons sold through transloads active at December 31, 2018		13		8		1,297
Tons sold through transloads not active at December 31, 2018						75
Tons sold through transloads in 2018						1,372

Quarter Ended	High Price		Low Price		Distributions Declared Per Unit
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	$	—

March 31, 2018	$	10.03	$	5.99	$	—
June 30, 2018	$	9.16	$	5.96	$	—
September 30, 2018	$	7.88	$	3.99	$	—
December 31, 2018	$	4.27	$	1.45	$	—

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

	($ in thousands)
Debt (1)	$	349,935	$	42,402	$	87,431	$	220,102	$	—
Railcar leases (2)		390,906		42,156		93,293		79,403		176,054
Unsecured notes (2)		7,922		2,724		5,198		—		—
Other operating leases (3)		12,409		2,744		2,765		1,673		5,227
Purchase commitments (4)		62,172		18,189		22,500		14,160		7,323
Minimum royalty payments (5)		4,957		508		1,090		380		2,979
Total	$	828,301	$	108,723	$	212,277	$	315,718	$	191,583

Emerge Energy Services LP Consolidated Financial Statements:

Report of Independent Registered Public Accounting Firm		82

Consolidated Balance Sheets as of December 31, 2018 and 2017		83

Consolidated Statements of Operations for the Years Ended December 31, 2018, 2017 and 2016		84

Consolidated Statements of Partners’ Equity for the Years Ended December 31, 2018, 2017 and 2016		85

Consolidated Statements of Cash Flows for the Years Ended December 31, 2018, 2017 and 2016		86

Notes to Consolidated Financial Statements		87

		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

	December 31, 2018			December 31, 2017
Customer A		16	%		17	%
Customer B		15	%		20	%
Customer C		14	%	*
Customer D	*				13	%

	December 31, 2018			December 31, 2017			December 31, 2016
Customer A		25	%		18	%		13	%
Customer B		13	%	*				16	%
Customer C		12	%		17	%		22	%
Customer D	*				11	%	*

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

	Cost		Accumulated Amortization		Net

	($ in thousands)
December 31, 2018:
Non-compete agreement	$	50	$	44	$	6
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

Year Ending Year Ending December 31,	($ in thousands)
2019	$	1.5
2020		1.5
2021		1.5
2022		1.5

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

	($ in thousands)
Year ending December 31,
2019	$	42,156	$	2,744	$	508	$	18,189
2020		42,544		1,874		533		12,187
2021		50,749		891		557		10,313
2022		42,188		863		190		7,632
2023		37,215		810		190		6,528
Thereafter		176,054		5,227		2,979		7,323
Total	$	390,906	$	12,409	$	4,957		62,172
Less amount representing interest								(404	)
Total less interest							$	61,768

	($ in thousands)
Balance at December 31, 2017	$	5,557
Adjustments		(221	)
Accretion		30
Payments		(4,467	)
Balance at December 31, 2018	$	899

	Total Units			Phantom Units			Restricted Units			Fair Value per Unit at Award Date
Outstanding at Outstanding at December 31, 2017		333,821			310,780			23,041		$	13.10
Granted		338,529			301,561			36,968		$	2.91
Vested		(134,921	)		(111,881	)		(23,040	)	$	11.27
Forfeitures		(6,375	)		(6,375	)		—		$	8.71
Outstanding at Outstanding at December 31, 2018		531,054			494,085			36,969		$	7.12

	December 31,				Classification
	2018		2017

	($ in thousands)
Warrant liability	$	281	$	2,811	Other long-term liabilities

Name	Age	Position
Ted W. Beneski	62	Chairman of the Board and Director
Rick Shearer	68	Chief Executive Officer and Director
Deborah Deibert	54	Chief Financial Officer
Warren B. Bonham	56	Vice President and Director
Nadya Kurani	45	Chief Accounting Officer
Kevin Clark	62	Independent Director
Mark Gottfredson	61	Independent Director
Peter Jones	61	Director
Francis J. Kelly, III	62	Independent Director
Eliot E. Kerlin, Jr.	44	Director
Victor L. Vescovo	53	Director
Eugene I. Davis	64	Independent Director
William L. Transier	64	Independent Director

Named Executive Officer	2018 Annual Base Salary
Rick Shearer	$	551,250
Deborah Deibert	$	308,711
Warren Bonham	$	231,522
Nadya Kurani	$	196,028

Named Executive Officer		2018 Target Bonus as a Percent of Base Salary
Rick Shearer		80%
Deborah Deibert		50%
Warren Bonham		40%
Nadya Kurani		40%

Named Executive Officer	Adjusted EBITDA		Payout (as a percentage of base salary)
Rick Shearer
Threshold	$	86,000,000	30%
Target	$	111,000,000	80%
Deborah Deibert
Threshold	$	86,000,000	18.8%
Target	$	111,000,000	50%
Warren Bonham
Threshold	$	86,000,000	15%
Target	$	111,000,000	40%
Nadya Kurani
Threshold	$	86,000,000	15%
Target	$	111,000,000	40%

Name	Company Contributions to 401(k) Plan ($)		Company Contributions to Health Savings Account ($)		Reimbursement for Executive Physical Allowance ($)		Auto Reimbursement($)		Total ($)
Rick Shearer		23,868		1,500		3,000		23,000		51,368
Deborah Deibert		23,868		2,250		—		—		26,118
Warren Bonham		—		—		3,677		—		3,677
Nadya Kurani		15,217		2,250		—		—		17,467

			Estimated Possible Payouts Under Non-Equity Incentive Plan Awards (1)
Name	Grant Date		Threshold ($)		Target ($)		Maximum (S)		All Other Stock Awards: Number of Units (#)(3)		Grant Date Fair Value of Stock Awards ($)
Rick Shearer		—		165,375		441,000		—		—		—
Rick Shearer	12/14/2018			—		—		—		112,961		243,996
Deborah Deibert		—		57,883		154,356		—		—		—
Deborah Deibert	12/31/2018			—		—		—		30,000		46,200
Warren Bonham		—		24,728		92,609		—		—		—
Nadya Kurani		—		29,404		78,411		—		—		—
Nadya Kurani	12/31/2018			—		—				16,000		24,640

Name	Number of Units Acquired on Vesting (#)		Value Realized on Vesting ($)(1)
Rick Shearer		83,473		191,820
Deborah Deibert		9,137		57,051
Warren Bonham		—		—
Nadya Kurani		3,619		26,021

Name (1)	Fees Earned in Cash ($)(2)		Stock Awards ($)(3)		Total ($)
Kevin Clark		65,626		78,750		144,376
Mark Gottfredson		55,124		78,750		133,874
Peter Jones (4)		26,251		78,750		105,001
Francis J. Kelly, III		65,626		78,750		144,376

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
Eugene Davis	William L. (“Bill”) Transier

Name of Beneficial Owner	Common Units Beneficially Owned		Percentage of Common Units to be Beneficially Owned
Insight Equity (1)		7,168,545	23.0%
Ted W. Beneski (2)		1,172,624	3.8%
Rick Shearer		328,603	1.1%
Victor L. Vescovo		139,752	*
Warren B. Bonham		6,899	*
Deborah Deibert		23,663	*
Mark Gottfredson		125,082	*
Francis J. Kelly III		40,226	*
Kevin Clark		42,705	*
Eliot E. Kerlin, Jr.		2,408	*
Peter Jones		36,764	*
Nadya Kurani		9,053	*
All directors and officers as a group (11 persons)		9,096,324

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		531,054	$	—		740,516
Equity compensation plans not approved by security holders		—		—		—
Total		531,054	$	—		740,516


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.

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).

Exhibit Number		Description

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).

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 (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).

Exhibit Number		Description

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).

10.25		Non-Employee Director Compensation Letter, dated January 31, 2019, by and between Emerge Energy Services GP LLC, Emerge Energy Services LP and Eugene I. Davis (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K, filed with the SEC on February 8, 2019).

10.26*		Non-Employee Director Compensation Letter, dated April 23, 2019, by and between Emerge Energy Services GP LLC, Emerge Energy Services LP and William L. Transier.

10.27		Senior Secured Priming and Superpriority Debtor-In-Possession Credit and Security Agreement, dated as of July 19 2019, among Emerge Energy Services, LP, as parent guarantor, Emerge Energy Services Operating LLC and Superior Silica Sands LLC, as borrowers, the financial institutes which are now or which hereafter become a party thereto, as lenders and HPS Investment Partners, LLC, as administrative agent for the lenders and collateral agent for the secured parties (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the SEC on July 19, 2019).

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.

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)