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”).

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”)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.

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		—		—

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.

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

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:

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	$	—

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

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

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		—		—