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TABLE OF CONTENTS
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

 

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

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Form 10-K

Commission File No. 001-35912

EMERGE ENERGY SERVICES LP
(Exact name of registrant as specified in its charter)

180 State Street, Suite 225, Southlake, Texas 76092
(Address of principal executive offices)

(817) 488-7775
(Registrant's telephone number, including area code)

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

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

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

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

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

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

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

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

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

As of June 28, 2013, the last business day of the registrant's second fiscal quarter of 2013, the aggregate market value of the registrant's common units held by non-affiliates of the registrant was $247,186,628 based on the closing price as reported on the New York Stock Exchange composite tape on that date.

As of March 17, 2014, 23,628,208 common units were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE: None

   

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CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

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

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

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GLOSSARY OF SELECTED TERMS

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

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

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

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

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

API:  American Petroleum Institute.

Backwardation:  A market situation in which the futures price of a commodity is below the expected future spot price. Contango is the opposite market condition.

Barrel:  An amount equal to 42 gallons.

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

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

Contango:  A market situation in which the futures price of a commodity is higher than the expected future spot price. The opposite market condition is backwardation.

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.

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.

GAAP:  Generally accepted accounting principles in the United States.

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.

ISO:  International Organization for Standardization.

Low sulfur diesel:  Diesel fuel that has a sulfur content of greater than 15 ppm and a maximum sulfur content of 500 ppm.

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

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

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

ppm:  Parts per million.

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

Renewable Identification Numbers ("RINs"):  Serial numbers assigned to batches of biofuel for the purpose of tracking its production, use, and trading as required under Energy Independence and Security Act of 2007.

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.

Ultra low sulfur diesel:  Diesel Fuel that has a maximum sulfur content of 15 ppm.

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

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

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PART I

ITEM 1.        BUSINESS

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

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

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

Overview

We are a publicly-traded limited partnership formed in 2012 by management and affiliates of Insight Equity to own, operate, acquire and develop a diversified portfolio of energy service assets.

Our current operations are organized into two service-oriented business segments: our Sand segment and our Fuel segment (formerly referred to as our "Fuel Processing and Distribution" segment). Through our Sand segment, we are engaged in the businesses of mining, processing, and distributing silica sand, a key input for the hydraulic fracturing of oil and gas wells. Our Fuel segment processes transmix, distributes refined motor fuels and renewable fuels, operates bulk motor fuel storage terminals, and provides complementary services. We believe this diverse set of operations provides a stable cash flow profile when compared to companies with only one line of business.

We conduct our Sand operations through our subsidiary SSS and our Fuel operations through our subsidiaries Direct Fuels and AEC. We believe that our subsidiary brands, especially our SSS brand, have significant name recognition and a strong reputation with our customers.

Our principal offices are located at 180 State Street, Suite 225, Southlake, Texas 76092. Our telephone number is (817) 488-7775 and our website address is www.emergelp.com.

Business Strategies

The primary components of our business strategy are:

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Focus on business results and total distributions.  We focus on optimizing our business results and maximizing total distributions. The board of directors of our general partner adopted a policy under which distributions for each quarter are equal the amount of available cash we generate each quarter. In addition, our general partner has a non-economic general partner interest and

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no incentive distribution rights, and, accordingly, all of our unitholders, including our sponsor, receive 100% of our cash distributions on a pro rata basis.

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Seek contractual cash flow stability.  In our Sand segment, we intend to continue securing long-term take-or-pay, fixed-volume, and efforts-based contracts with existing and new customers in order to cover the substantial majority of our production capacity. Currently, 34% of our production capacity at our New Auburn and Barron facilities is covered by long-term contracts, and 93% of our sales in the year ended December 31, 2013 were to contracted customers. As of December 31, 2013, we had 1.3 million tons under long-term contract with a weighted average remaining term of 2.8 years. In our Fuel segment, our contract structure is designed to capture a stable margin, as the price differential between the refined products indices at which we purchase transmix and wholesale fuel and the sales price of the refined products fluctuates in a narrow range. In addition, we typically resell our refined products within 7 to 10 days after acquiring our transmix, wholesale fuel and other feedstock supply, which reduces our exposure to fluctuations in the underlying indices. We also seek to lease additional space in our terminal tanks to refiners and large fuel wholesalers, where we can capture both fixed monthly margins and fixed per-gallon throughput margins that are independent of the underlying commodity price. In addition, we also enter into financial hedging arrangements to partially mitigate our direct exposure to commodity price and market index fluctuations.



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Capitalize on compelling industry fundamentals.  We believe the frac sand market offers attractive long-term growth fundamentals, and we expect to continue to position ourselves as a producer of coarse, high-quality "Northern White" frac sand located in Wisconsin's Jordan, St. Peter and Wonewoc formations. Over the past several years, the demand for frac sand in the United States and Canada has grown significantly, primarily as a result of increased horizontal drilling, technological advances that allowed for the development of many unconventional resource formations, increased proppant use per well and cost advantages over other proppants such as resin coated sand and ceramic alternatives. In particular, the demand for coarse Northern White sand, such as the type we mine and sell from our Wisconsin facilities, is very strong among end users who are focused on the extraction of oil and liquids-rich natural gas. We believe frac sand supply will continue to be constrained by a variety of factors, including but not limited to: (i) the difficulty in finding reserves suitable for use as frac sand, which are largely limited to select areas of the United States and which must meet the technical specifications of the American Petroleum Institute ("API"); (ii) challenges associated with locating contiguous reserves of frac sand sufficient to justify the capital investment required to develop a mine and processing plant; and (iii) securing necessary local, state and federal permits required for operations. It has been our observation that spot market prices have strengthened since our initial public offering on May 14, 2013, especially for the coarser grades, and we believe that we are well positioned to increase our average selling price as we bring in new spot and contract sales.



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Capitalize on organic growth opportunities and optimize existing assets.  We intend to focus on organic growth opportunities that complement our existing asset base or provide attractive returns in new geographic areas or business lines. In our Sand segment, we continue to seek to sell our full capacity at our newly-constructed Barron facility, as well as find alternative markets for sales of our native sand product at our Kosse, Texas facility. We are also constructing two new fully-permitted mines and wet plants near our New Auburn and Barron facilities, which we expect to be completed in mid-2014 and which we further expect to significantly lower our average cost of sand upon completion. In our Fuel segment, we believe there are several opportunities to contract additional transmix supplies, which we can process using existing excess capacity, and increase both wholesale and terminal volumes.

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Access new and adjacent markets using existing capabilities.  We are exploring and will continue to explore opportunities to expand our businesses into new markets by leveraging our existing operations and our historical experiences. In our Sand segment, we will continue to pursue opportunities created by the demand for our reserves and to use our surplus processing and storage capacity in order to meet the needs of our customers. We also developed a total supply chain solution for our customers, designed to deliver sand anywhere from the railcar at the mine to within 60 miles of the wellhead. We believe this supply chain solution provides our customers with a streamlined order process that yields a lower total delivered product cost while generating incremental earnings for us and enabling us to reach a broader set of customers. For example, given our multiple railroad, trucking and barging logistics capabilities, we have started to explore potential sales opportunities in Central and South American countries. We have also identified dedicated logistics partners in Mexico should that market open up to Northern White frac sand over the next several years. If such opportunities materialize, we would expect to select our customers in those countries by employing the same disciplined financial criteria that we have used with respect to our existing customers. In our Fuel segment, we built the capability to blend additives into our refined products, which allows us to sell branded petroleum products in addition to unbranded products, and which we believe was critical to allow us to source new terminaling customers in the past year. We also intend to leverage our existing customer relationships to expand our footprint in Dallas-Fort Worth and Birmingham and their adjacent markets.



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Grow business through strategic and accretive business or asset acquisitions.  We plan to selectively pursue accretive acquisitions in our areas of operation that we believe will allow us to realize operational efficiencies by capitalizing on our existing infrastructure, personnel and commercial relationships in energy services, and we may also seek acquisitions in new geographic areas or complementary business lines. For example, we have identified several highly attractive frac sand deposits and developments in properties adjacent to or in close proximity to our existing Wisconsin operations, allowing for the opportunity to contract additional reserves and additional finished product capacity. We also believe that we can replicate our transmix, wholesale and terminal business activities successfully in other regions of the United States.



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Maintain financial strength and flexibility.  We intend to maintain financial strength and flexibility to enable us to pursue our growth strategy, including acquisitions, organic growth and asset optimization opportunities as they arise. As of December 31, 2013, we had $2.2 million of cash on hand and $90.3 million of additional liquidity available under our revolving credit facility.

Competitive Strengths

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

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High quality, strategically located assets.  We currently operate several scalable frac sand production facilities in and around New Auburn, Wisconsin, Barron, Wisconsin and Kosse, Texas. Our facilities in Wisconsin are supported by approximately 80.2 million tons of proven recoverable sand reserves and our facility in Texas is supported by approximately 28.2 million tons of proven recoverable sand reserves. We believe that our Wisconsin reserves provide us access to a disproportionate amount of coarse sand (16/30, 20/40 and 30/50 mesh sands) compared to other Northern White deposits located in Wisconsin's Jordan, Mt. Simon, St. Peter and Wonewoc formations. Our recent sample boring data and production data indicated that our Wisconsin reserves contain deposits of nearly 35% 40 mesh or coarser substrate, with our Barron reserves being comprised of more than 60% 50 mesh or coarser substrate. 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, of which we believe we are the market's largest

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supplier. Our access to coarse sand provides us with lower processing costs relative to mines with finer sand reserves and enables us to better serve the current levels of high demand for coarse frac sand that is related to increased hydraulic fracturing activities focused on the recovery of oil and liquids-rich gas in the United States.

Our transmix facilities are centrally located in the Dallas-Fort Worth and Birmingham metropolitan areas. The population in these areas is forecasted to increase at a weighted growth rate greater than the national average between 2010 and 2030, which is expected to drive incremental demand for the products and services we offer through our Fuel segment. Because pipelines typically represent the most economical means of transporting petroleum products, proximity to refined products pipelines is critical to the economic success of our transmix, wholesale and terminal operations. We are able to receive products via two different pipelines owned by the Explorer Pipeline Company and one owned by a major independent refiner at our facility in the Dallas-Fort Worth metropolitan area and via the Plantation and Colonial pipelines at our Birmingham facility.

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Stable cash flows.  In our Sand segment, we currently sell our products primarily under long-term supply agreements. A portion of our supply agreements are take-or-pay contracts under which the customer will be obligated to pay us an amount designed to compensate us, in part, for lost margins for the applicable contract year on any minimum annual volumes that are not purchased by that customer. Any sales of the shortfall volumes to other customers on the spot market would provide additional margin on these volumes. Collectively, sales to customers with take-or-pay or fixed-volume sales agreements in 2013 and 2012 accounted for 73% and 91% of our total Sand segment sales, respectively. Total sales to customers under all long-term contracts, including take-or-pay, fixed-volume and efforts-based contracts, accounted for 93% and 92% of our total Sand segment sales in 2013 and 2012, respectively.

In our Fuel segment, our contract structure is designed to capture a stable margin, as the price differential between the refined products indices at which we purchase transmix and wholesale supply and the sales price of the refined products fluctuate in a fairly narrow range. While a meaningful portion of our transmix business is conducted on a spot basis, we currently purchase 72% of our supply of transmix pursuant to exclusive contracts with terms ranging from 12 to 48 months, with a volume-weighted average remaining duration of 8 months as of December 31, 2013. In addition, we have throughput agreements with major refining and fuel marketing companies with terms of up to 45 months, which provide stable, fee-based revenue.

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Intrinsic logistics advantage.  In our Sand segment, the logistics capabilities of our New Auburn and Barron facilities enable us to serve all major United States and Canadian oil and natural gas producing basins. Our New Auburn facility has 4.5 miles of on-site rail track linked to a rail line owned by Union Pacific and our Barron facility has 3.5 miles of on-site rail track tied into a Canadian National rail line. Between our two Wisconsin facilities, we have storage space for over 850 railcars. As of December 31, 2013, we had a total of 2,803 railcars in our fleet, including 1,745 dedicated customer cars and 1,058 railcars under lease with a weighted average term of 29 months. We have another 3,400 railcars under order for delivery in 2014 and early 2015. As of December 31, 2013, we had twelve transload facilities in North America, each of which is positioned to serve a number of our target markets.

Our logistics capabilities enable efficient loading of sand and minimize rail car turnaround times, and our facilities are able to accommodate unit trains. We believe we are one of a small number of frac sand producers connected to more than one Class One rail line, and this provides us with the capability to serve virtually all North American shale plays economically using a single-line haul, which reduces transit time and freight cost for our customers.

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



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



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



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after satisfying our minimum purchase obligations, a large proportion of the costs we incur in our Sand segment are only incurred when we produce saleable frac sand;



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



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mineral royalty expenses that were less than 1.7% of our Sand revenues in 2013;



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



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



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Significant organic growth capacity.  We continue to capitalize on the capacity at our Barron facility, which commenced operations in late December 2012. For the year ended December 31, 2013, we produced and sold 1.2 million tons through this facility, equivalent to a capacity utilization of 50%. We expect to use the remaining capacity to continue to establish new customer relationships through new long-term contracts and to enter into spot sales at favorable market prices, which have been higher than long-term contract prices in the recent past. In addition, we believe that this capacity will continue to position us well to attract customers currently relying on other frac sand producers when those customers have the opportunity to renegotiate their sand supply contracts or seek out a new supplier.



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Strong reputation with our customers, suppliers and other constituencies.  Our management and operating teams have developed longstanding relationships with our customers, suppliers and other constituencies. We currently sell to ten of the eleven largest North American hydraulic fracturing service providers. Based on our track record of dependability, timely delivery and high-quality products that consistently meet customer specifications, we believe that we are well positioned to secure additional contracted commitments in the future, and that our product mix and customer service will continue to benefit our reputation within the frac sand industry. In our Fuel segment, we have established long-term supply relationships with major refining, midstream and marketing companies that provide us with a steady source of supply at competitive prices.



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Ability to identify and respond to changing market dynamics.  We believe we have designed our assets and business model to permit us to adapt to changing market conditions. For example, our Wisconsin facilities can optimize our production mix so that up to 20% of our production volume can fluctuate between coarse and fine sands. This optimization does not significantly impact our production yields or costs, yet we can still meet all API specifications, thereby allowing us the flexibility to respond efficiently to shifts in pricing and customer demand dynamics. We have also identified opportunities to utilize excess dry plant capacity at our Kosse, Texas frac sand processing facility to provide additional product offerings to our customers in the southwestern United States. Finally, we have significant reserves of fine mesh sand and believe that we will be well positioned to capture opportunities created by changing market trends in the relative prices of crude oil and dry natural gas.

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Experienced management team with industry specific operating and technical expertise.  The top three management team members of our Sand segment have more than 75 years of combined industry experience. They have managed numerous frac sand mining and processing plants, successfully led acquisitions in the industry and developed multiple greenfield industrial minerals mining and processing operations. Most recently, this management team identified our existing Wisconsin facilities and designed, permitted and commenced each facility's operations within 12 months. We believe that our customers value our dedication to customer service, our reliable delivery, and our focus on high-quality product and that these give us a competitive advantage in the market. In addition, because of the experience of our staff, we believe that we are able to operate our sand facilities at a much lower per-ton overhead than our competition.

The top five management team members of our Fuel segment have significant experience and complementary skills in the areas of transmix processing, acquiring, integrating, financing and managing refined product terminals and biodiesel manufacturing and have in excess of 100 years of combined industry experience.

Our Business Segments

Sand Segment

Our Sand segment mines, processes and distributes high quality silica sand, a key input for the hydraulic fracturing of oil and gas wells. Our facilities consist of two dry plants located in New Auburn and Barron, Wisconsin with a total permitted capacity of 3.8 million finished tons per year, and four wet plants and mine complexes, including two currently under construction, that supply the dry plants with Northern White silica sand, which we believe is the highest-quality raw frac sand available. We also have a third 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. As of December 31, 2013, we also have twelve transload facilities located throughout North America, as well as a fleet of over 2,803 rail cars. In 2014, we expect to materially increase both the number of transload sites in our network and the railcars in our fleet.

Our Sand segment is experiencing rapid growth due to recent 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. We believe that the premium geologic characteristics of our Wisconsin sand reserves, the strategic location of our sand mines, our location on two Class One rail lines, our extensive transload and logistics network, the industry experience of our senior management team, and the reputation that SSS has with our customers have positioned 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 on the surface and above the water table. We mine our sand using an open pit process, wherein we remove the topsoil, which is set aside, and then remove other non-economic minerals, or "overburden," to expose the sand deposits. We then "bump" the sand using explosives on the mine face, which causes the sand to fall into the pit, where it is then carried by truck to the wet plant operations. 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, and then replace the topsoil. At our wet plant, the mined sand goes through a series of processes designed to crush the sand to individual grains, cleanse it of impurities and unusable materials, and remove sand particles too fine to be of commercial use. 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 fine grains and other materials are separated through a series of settlement ponds. We re-use all of the water in our wet process that does not evaporate. 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 our customers.

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Our frac sand facilities are located in New Auburn, Wisconsin, Barron, Wisconsin and Kosse, Texas. Based on the reports of our third-party engineers we have approximately 108.4 million tons of proven recoverable ISO and API quality sand reserves, including approximately 80.2 million tons of proven recoverable reserves that will supply our Wisconsin facilities. We are currently capable of producing up to 4.4 million tons and 6.4 million tons of dry and wet sand per year, respectively, from our current facilities. Upon the completion of two additional wet plants to service our Barron facility, which we expect to occur in the first half of 2014, we anticipate having total wet sand processing capacity of 9.0 million tons per year, including 7.5 million tons per year of Northern White sand. We believe that the coarseness, conductivity and crush-resistant properties of our Wisconsin reserves and our facilities' interconnectivity to rail and other transportation infrastructure afford us a cost 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 liquids-rich gas production to all major unconventional resource basins currently producing throughout North America.

Our Wisconsin sand reserves give us access to a wide range of high-quality sand that meets or exceeds all API specifications and includes a significant concentration of 16/30, 20/40 and 30/50 mesh sands, which have become the preferred sand for oil and liquids-rich gas drilling applications. We believe that our Wisconsin reserves provide us access to a disproportionate amount of coarse sand (16/30, 20/40 and 30/50 mesh sands) compared to other Northern White deposits located in Wisconsin's Jordan, St. Peter and Wonewoc formations. 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 Arland, 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, which along with other coarse sands is currently subject to high demand from our customers and which we believe commands a significant price premium. The coarseness of our reserves also provides us with a meaningful cost advantage, as companies with a low concentration of coarse sand must typically expend the resources necessary to mine a large amount of fine grain sand that currently has less commercial value. Further, if demand increases for dry gas drilling applications that utilize fine grain sands, our production costs per ton of sand would improve and we believe that we would be well-positioned to compete in that market. Our Wisconsin dry plants are fully enclosed, which means that we have two of the very few plants in Wisconsin that are capable of running year-round, regardless of the weather. 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.

Our mine, wet plant and dry plant in Kosse, Texas operate year-round. We operate our Kosse facilities with crews of four to six employees who work twelve-hour shifts and average 40 hours per week. This allows us to optimize facility utilization.

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

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The following table provides information regarding our current and planned frac sand production facilities as of December 31, 2013.

 

Mineral Reserves

We believe that our strategically located mines and facilities provide us with a large and high-quality mineral reserve base. Were we to operate our existing dry plants at full capacity, our reserves would supply us with 20 years of Northern White frac sand and 47 years of native Texas sand.

The coarseness and conductivity of the Northern White frac sand that we mine in Wisconsin significantly enhances recovery of oil and liquids-rich gas by allowing hydrocarbons to flow more freely than would be possible with smaller, finer frac sands. In addition, its crush resistant properties enable Northern White frac sand to be used in deeper drilling applications than the frac sand produced from mineral deposits located in Texas, Arkansas or other southern United States locations. We believe the higher crush strength properties of our Northern White sand provides us with a significant competitive advantage in supplying frac sand.

We categorize our reserves as proven recoverable in accordance with SEC definitions and have further limited the definition to apply only to sand reserves that we believe could be extracted at an average cost

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that is economically feasible. According to such a definition, we estimate that we had a total of approximately 108.4 million tons of proven recoverable mineral reserves as of December 31, 2013. The quantity and nature of the mineral reserves at each of our properties are estimated first by third-party geologists and mining engineers and we internally track the depletion rate on an interim basis. In addition, Short Elliot Hendrickson Inc. ("SEH") prepared an estimate of our proven mineral reserves at our New Auburn mine, and Cooper Engineering Company, Inc. ("Cooper Engineering") prepared estimates of our proven mineral reserves at our other Wisconsin mine locations, while Westward Environmental, Inc. ("Westward") prepared estimates of our proven mineral reserves at our Kosse facility, each as of December 31, 2013. Our external geologists and engineers update our reserve estimates annually, making necessary adjustments for operations at each location during the year and additions or surveying, drill core analysis and other tests to confirm the quantity and quality of the acquired reserves.

As of December 31, 2013, we owned 100% of our mineral reserves in Texas and leased 100% of our reserves in Wisconsin from third-party landowners, with our Wisconsin leases expiring at various times between 2036 and 2038. We do not anticipate any issues in renewing these leases should we decide to do so. Consistent with industry practice, we conduct only limited investigations of title to our properties prior to leasing. Title to lands and reserves of the lessors or grantors and the boundaries of our leased priorities are not completely verified until we prepare to mine those reserves.

To opine as to the economic viability of our reserves, our independent third-party engineers reviewed our operations at the time of their proven recoverable reserve determination. Their findings were then incorporated into their reserve calculations and the reserve estimates reflect the quantity of sand that can be recovered under a similar cost structure. The cutoff grade used by SEH in estimating our reserves considers only sand that will not pass through a 65 mesh screen as proven recoverable reserves, meaning that only sands with mesh sizes coarser than 65 are included in their estimates of our proven recoverable reserves. Cooper Engineering's estimate of our proven recoverable reserves considers only the proportion of sand grains falling between 20 and 70 mesh API sizes. The cutoff grade used by Westward in estimating our reserves considers only sand that falls between 20 and 140 mesh API sizes as proven recoverable reserves.

Mines and Wet Plants

New Auburn

Our New Auburn wet plant was constructed and commenced operations in 2011. The facility is a steel structure and relies primarily on industrial grade aggregate processing equipment to scrub and process up to 2.0 million tons per year of wet sand. It is strategically located approximately 12 miles from our New Auburn dry plant, to which we have year-round trucking access.

We lease the mineral rights to a 418-acre mine site adjacent to our New Auburn wet plant. As of December 31, 2013, the mine site contained approximately 20.0 million tons of proven recoverable reserves, of which substantially all were coarser than 70 mesh according to our third-party engineers. These leases expire in 2036.

The deposits found in our open-pit New Auburn mine are Cambrian quartz sandstone deposits that produce high-quality Northern White frac sand and have a minimum silica content of 99%. The knoll from which we mine sand can contain up to 90 feet of unsalable overburden but yields pay zones that are up to 105 feet deep and that contain material that is predominately in the 20/60 grain size distribution. 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. A third-party contractor that operates our mine at this location, and they use heavy equipment to mine the loose sandstone deposit from a wooded knoll up to approximately 180 feet in elevation above the surrounding seasonally farmed crops. As of December 31, 2013, excavating activities consisting of mining, overburden removal and reclamation had taken place on approximately 70 of the 418 acres of our New Auburn property.

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In 2011, we awarded Fred Weber, Inc. ("Fred Weber") a five-year contract for the entirety of our New Auburn mining operations and for a portion of our wet processing needs at that facility. Under this contract, Fred Weber financed and built the wet plant at our New Auburn facility. Fred Weber now mines the sand reserves, creates stockpiles of washed sand and maintains the plant and equipment at New Auburn. We agreed, under a take-or-pay arrangement, to purchase 300,000 tons of washed sand from Fred Weber each year that the plant is in operation. We pay Fred Weber a set price per ton of washed sand, subject to adjustments each operational year for diesel prices, the quality of the sand mined and the quantity of sand purchased. During the term of the agreement Fred Weber will own the wet plant along with the equipment and other temporary structures used for mining on the property. At the end of the five-year term of the agreement or following a default under the contract by Fred Weber, we have the right to take ownership of the wet plant and other mining equipment without charge. Subject to certain conditions, ownership of the plant and equipment will transfer from Fred Weber to us at the expiration of the term.

Arland

Our Arland mine consists of five adjacent mineral deposits in Barron, Wisconsin that together account for 364 acres and that contain approximately 12.0 million tons of proven recoverable sand reserves, based on the report of our third-party independent mining engineers. This facility also includes a wet plant with the capacity to process 1.2 million tons per year. This mine is located approximately 11.5 miles from our Barron dry plant.

The deposits found in our Arland mine are substantially similar to the sand found in our New Auburn mine. We use heavy equipment to mine sand from rolling hills up to approximately 60 feet in elevation above the surrounding seasonally farmed crops. The nearby hills yield material that is predominately in the 20/70 grain size distribution and will be mined in phases lasting from six months to one year in duration, after which the property will be reclaimed in a manner that provides the landowners of each mine site with additional cropland. As of December 31, 2013, excavating activities consisting of mining, overburden removal and reclamation had taken place on approximately 69 acres of our Arland property.

LP Mine

In 2013, we entered into a series of leases in Barron, Wisconsin, adjacent to our Arland Mine. These account for 145 acres and contain approximately 8.7 million tons of proven recoverable sand reserves, based on the report of our third-party independent mining engineers. We are currently building a wet plant at this site that will have the capacity to process 1.0 million tons per year. The quality of the deposits is substantially identical to those of the Arland Mine. As is the case with our Arland mine, we intend to use these reserves to supply our Barron dry plant with washed sand.

Thompson Hills

In 2013, we entered into a series of leases in Barron, Wisconsin, approximately 25.5 miles from our Barron dry plant and approximately 15 miles from our New Auburn dry plant. These leases account for 580 acres and contain approximately 39.5 million tons of proven recoverable sand reserves, based on the report of our third-party independent mining engineers. Once fully permitted, we plan to commence construction of a wet plant capable of producting 1.6 million tons per year. We expect that the mine and wet plant will be fully operational by mid-2014. We intend to use these reserves to supply our Barron dry plant with washed sand, but we may also use this washed sand at our New Auburn plant.

The deposits found in our Thompson Hills mine are substantially similar to the sand found in our New Auburn mine. According to our third party engineer, the reserves are predominately in the 20/70 grain size distribution. We plan to mine the deposit in phases lasting from six months to one year in duration, after which the property will be reclaimed in a manner that provides the landowners of each mine site with additional cropland.

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Kosse

We own the mineral rights to a 225-acre mineral deposit located in Kosse, Texas, adjacent to our Kosse dry plant. The deposit has a minimum silica content of 99% and controlling attributes that include sand grain crush strength and size distribution. As of December 31, 2013, the Kosse mineral deposit contained approximately 28.2 million tons of proven recoverable reserves, which we process into a high-quality, 100 mesh frac sand that is particularly well suited to drilling for dry natural gas. The wet plant at our Kosse facility is capable of producing up to 1.5 million tons per year of wet sand. We are not obligated to make any royalty payments in connection with our mining operations at this location. We use heavy equipment to mine sand from the open-pit. The current mining area of our Kosse property covers approximately 95 acres and no reclamation has been performed.

Midwest Frac

In order to secure access to additional raw Northern White frac sand, we entered into a ten-year supply agreement with Midwest Frac. Pursuant to the terms of this agreement, we constructed a wet plant with the capacity to process 1.2 million tons per year on land owned by Midwest Frac that is approximately 10 miles from our Barron dry plant. Under the supply agreement, we are obligated to purchase at least 200,000 tons of wet sand and have the right to purchase an annual allotment of up to 500,000 tons of wet sand from Midwest Frac's mine per year.

Based on our observations, we believe the coarseness, conductivity and crush-resistant properties of the raw sand mined by Midwest Frac is substantially similar to the properties of the sand we mine from our Arland facility. The raw sand is processed at the wet plant facility located on Midwest Frac's property and subsequently shipped via truck to our Barron dry plant. Midwest Frac will use a portion of its proceeds from processing the first 600,000 tons of wet sand sold to repay us for our investment, plus interest, in the wet plant we constructed on its property. In accordance with our agreement, Midwest Frac will have the right to acquire the wet plant from us at no cost upon the earlier of (i) the expiration of the agreement in 2022 or (ii) the date on which the total discounts we receive on the sand we purchase from Midwest Frac exceeds the cost we incurred to construct the wet plant plus an interest rate of six percent. The total capital we deployed to construct the wet plant on the land owned by Midwest Frac was approximately $2.7 million. As of December 31, 2013, Midwest Frac had processed 425,000 tons under the Supply Agreement.

Midwest Frac is also obligated to use our Barron dry plant to toll process 200,000 tons of sand per year. As of December 31, 2013, Midwest Frac had not toll-processed any sand. The supply agreement requires that we pay Midwest Frac $22 per ton of sand that we purchase. For the contract year ended August 31, 2013, we received a rebate that effectively reduced our price to $20 per ton as a result of Midwest Frac's failure to fulfill the toll processing provisions of our agreement. As the per-ton cash costs of purchasing sand from Midwest Frac is significantly higher than the per-ton cash costs we incur from the Arland mine and expect to incur from the LP and Thompson Hills mines, we expect to purchase no more than the contract minimum of 200,000 tons per year from Midwest Frac in the foreseeable future.

Dry Plant Facilities

New Auburn

Our New Auburn dry plant is located approximately 12 miles from our New Auburn mine and is strategically located near a county road that provides year-round trucking access. The facility is on 37 acres of land that we own in the town of New Auburn, Wisconsin along a short line that connects with the mainline of the Union Pacific ("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 and regardless of weather conditions, or roughly 50 rail cars, and has on-site rail car loading facilities capable of loading up to approximately 10,000 tons of frac sand into rail cars per day. 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

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six high capacity gyratory mineral separators, or "screeners." We constructed the facility and brought it online in late 2011, and fully enclosed the facility in mid-2012. In 2013 we completed the installation of our sixth Rotex screener that allowed us to increase our capacity to 1.4 million tons per year, the maximum allowable under our air permit.

Once processed and dried, sand from our New Auburn facility is stored in one of five on-site silos with a combined storage capacity of 4,500 tons. In addition to the 4,500 tons of silo capacity, we possess 4.5 miles of onsite rail track (3.0 miles of which is owned and 1.5 miles of which we access through a long term lease) that is tied into a rail line owned by UP and that is used to stage and store empty or recently loaded customer rail cars. Because of the cost efficiencies of shipping frac sand by rail, our strategic location adjacent to a UP short rail line provides our customers with the ability to transport Northern White frac sand from our New Auburn facility to all major unconventional oil and natural gas basins currently producing in the United States and Canada with direct access to high-activity areas of oil production in Texas, Oklahoma, Colorado and the western United States. Our location in Wisconsin also provides our customers with economical access to barging terminals on the Mississippi River as well as access to Duluth, Minnesota, for loading onto ocean going vessels for international delivery.

For the year ended December 31, 2013, our New Auburn facility produced and sold approximately 1.3 million tons of Northern White sand.

Barron

Our Barron dry plant is located in the township of Clinton, Wisconsin in Barron on 83 acres of land that we own. The facility is strategically located on a county road, which gives us year-round trucking access, and is situated along a spur owned by the Canadian National ("CN") railway that connects to the CN main line. Our Barron dry plant is an enclosed facility that has a rated production capacity of 8,800 tons per day year-round and regardless of weather conditions, or roughly 80 rail cars, and has on-site rail car loading facilities capable of loading up to approximately 10,000 tons of frac sand into rail cars per day. 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 Rotex screeners. Our railyard at Barron consists of 12 spur tracks and is capable of storing up to 430 railcars. We are currently expanding those facilities and expect to be able to store up to 490 railcars at Barron by mid-year. We completed construction of the Barron facility in 2012, and brought the facility online in the last two weeks of that year.

At Barron, we utilize 3.5 miles of existing rail track that connects our facility to the rail line owned by CN, making this facility one of only three active Wisconsin-based frac sand mines located on the CN line. Our direct connection to the CN line allows us to offer direct access to the rapidly growing oil and gas shale plays in northwestern Canada and the northeastern United States, including the Western Canadian Sedimentary Basin, the Marcellus Shale and the Utica Shale plays. The CN also presents us with access to emerging plays in the southern United States as well as the port of New Orleans, which provides us access to emerging markets in Latin America. We currently have eleven transload facilities that we operate and/or lease on the CN (including one facility on the BNSF rail line that we access through a two-line haul) in our target basins. In addition, we are currently the only frac sand provider in Wisconsin located on CN's high-capacity rail line, which is designed for rail cars with a 286,000 pound capacity, allows us to transport heavier loads and results in reduced transportation costs relative to competitors that only have access to lower capacity infrastructure.

For the year ended December 31, 2013, our Barron facility produced and sold approximately 1.2 million tons of Northern White sand.

Kosse

Our Kosse dry plant is located adjacent to our Kosse mine and wet plant on land we own in Kosse, Texas. The facility has a rated production capacity of 1,650 tons per day year-round. The dry plant utilizes a 200

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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. We upgraded the facility in 2009, and later redeployed some of its components to build our New Auburn facility.

The plant produces 100-mesh native Texas sand and is capable of producing a higher-cut 40/70 frac sand as well. In the past, we have also shipped washed Northern White sand from our Wisconsin operations in unit trains to Kosse where it is dried, screened and resold to oil field service companies servicing unconventional resource plays located in south and west Texas. The Kosse facility has three dedicated on-site 1,000 ton storage silos designed for loading trucks for delivery to local and regional markets.

For the year ended December 31, 2013, our Kosse facility produced and sold approximately 115,000 tons of frac sand. We are currently exploring a number of emerging markets for our Kosse sand to take advantage of its high quality sands. We also sell the sand to non-energy end users, specifically as sports sand for golf courses and stadiums.

Transportation Logistics and Infrastructure

As the frac sand market has evolved, the point of sale between producers and purchasers of frac sand is moving away from the traditional free-on-board ("FOB") mine model and closer to the wellhead. At our Kosse, Texas plant, orders are picked up by truck because most orders are transported 200 miles or less from our plant site. 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 several of our customers still purchase FOB mine, 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 60 miles of the wellhead. Given the relative weight of transportation and logistics expenditures as a percentage of total delivered frac sand cost, we believe such a service offering has allowed, and will continue to allow, us to generate incremental revenue and reach a broader set of customers while providing our customers with a streamlined order process and a lower total delivered product cost. Currently, we have invested in more than seven miles of owned or leased rail, built a fleet of company-leased rail cars, created a network of leased transload and terminal storage sites located near major shale plays and designed a supply chain management system that will allow us to flexibly and efficiently coordinate rail, truck and storage assets with customer order information. Several customers of our Barron facility currently utilize our total supply chain solution and pay us fees for the service. The majority of our sand volumes from our New Auburn facility are currently sold on FOB shipping point terms pursuant to our existing long-term contracts and, as a result, the customers of this facility generally coordinate delivery of purchased products to the intended destination in equipment that is owned or leased by them or their contractors.

We believe that the connectivity of our Barron facility to the CN, combined with our connection with the UP at our New Auburn facility, provide us enhanced flexibility to accommodate customers located in shale plays throughout North America. We also believe that access to these two rail lines allows us to provide single line hauls to most shale plays, resulting in fast transit times and a low delivered cost per ton. Using our existing on-site rail track, we have shipped sand in unit trains, which are dedicated trains (typically 80 to 120 rail cars in length) chartered for a single delivery destination that usually receive priority scheduling and result in a more cost-effective method of shipping than standard rail shipment, out of both our Barron and New Auburn facilities. In addition, we have the capability to transload product from either of our Wisconsin facilities to the other, allowing us to fulfill special orders in an expedited basis regardless of the optimal rail line.

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Transload Facilities

Due to limited storage capacity at or near the wellhead, our customers generally find it impractical to store frac sand in large quantities near their job sites. As a result, customers place a premium on a frac sand supplier's ability to maintain predictable and efficient product shipping schedules. The integrated nature of our production planning, rail car staging and product loading operations, combined with our more than seven miles of on-site rail infrastructure, provide us with a competitive advantage in serving customer needs as 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 further down the supply chain, we developed a network of transload facilities within a number of the major basins that we serve. As of December 31, 2013, we had agreements with operators of twelve transload storage facilities in North America. Below is a summary of the transload sites that we operate out of at December 31, 2013.

In addition to these twelve sites, we are also in the process of opening three transload sites in the Bakken Shale Play, Eagle Ford Shale Play and Western Canadian Sedimentary Basin.

In selecting transload sites, we focus on a number of factors, including distance to the wellhead and customer needs that are specific to the basin and drilling activity. Where available, we use silos to store our sand and work with the transload operators to ensure that in those locations where our sand is not the only sand sold that our sand is not comingled with that of our competitors; we refer to this as vertical storage. Where practical, we also utilize rolling storage, in which the sand remains in the railcar until it is loaded directly into a truck that will deliver the sand to the drill site.

To maintain the maximum flexibility and respond promptly to customer needs, we have focused on enhancing our railcar fleet. As the frac sand industry has evolved, so have the railcars that serve the industry, which means that we seek to have our fleet comprise, as much as possible, of dedicated 286,000 pound railcars designed specifically for loading and unloading of frac sand. As of December 31, 2013, we had a total of 2,803 railcars in our fleet, including 1,745 railcars that are owned or leased by our customers but dedicated to us, and 1,058 railcars that we lease with an average remaining term of 29 months. We anticipate that we will be able to renew these leases at favorable terms when they expire. We also have ordered an additional 3,400 railcars which we intend to lease, 525 of which have been or are expected to be delivered in the first quarter of 2014.

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Permits

In order to conduct our sand operations, we are required to obtain permits from various local, state and federal government agencies. The various permits we must obtain address such issues as mining, construction, air quality, water discharge and quality, 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, and are in the process of obtaining the remaining necessary permits for facilities under construction.

Fuel Segment

Our Fuel segment consists of our facilities in the Dallas-Fort Worth metropolitan area and in Birmingham, Alabama, which are operated by Direct Fuels and AEC, respectively. Through this segment, we acquire and process transmix, which is a blend of different refined petroleum products that have become co-mingled in the pipeline transportation process; sell wholesale petroleum products; provide third-party terminaling services; and provide other complementary products and services. In these two markets, we are able to offer our customers gasoline and diesel at market rates, 24 hours a day, seven days a week. A selected summary of our fuel capacity and volumes for the year ended December 31, 2013 follows:

In our transmix business, we acquire transmix from terminal operators and others which is delivered by pipeline or truck to our facilities. We then process the transmix into refined products such as conventional gasoline and low sulfur diesel, which we sell over our truck rack to third party distributors as well as off-road customers such as railroad operators. While a meaningful portion of our transmix business is conducted on a spot basis, we currently purchase approximately 72% of our supply of transmix pursuant to exclusive contracts having a volume-weighted average remaining duration of 8 months as of December 31, 2013. We design our contract structure to capture a stable margin, as the price differential between the indices at which we purchase transmix supply and the sales price of the corresponding refined products tends to be stable.

In our wholesale fuel business, we purchase fuel which is delivered to our tanks via pipeline, and which we then subsequently sell over our truck rack. We are also a shipper on the Colonial Pipeline, which allows us to bring refined products to our Birmingham facility from Gulf Coast refineries without paying third parties separate shipping charges. Our average holding period for transmix and wholesale gallons is 7-10 days, which serves to minimize the effects of daily fluctuations in fuel price.

In our terminaling business, we lease our terminal space to third parties who use our facilities to store refined petroleum products. We are able to charge customers for the storage, intake, and/or outtake of refined products. In 2013, we installed additive systems, which now allow us to sell branded gasoline in

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addition to the unbranded gasoline we have historically sold, which we believe will allow us to increase our terminal customers and revenue base over time.

Other services include blending of renewable fuels into petroleum products, the manufacture of biodiesel at our Birmingham facility and certain reclamation services, which consist primarily of tank cleaning services. We also are a net producer of Renewable Identification Numbers, or RINs, which we sell to reduce our cost of goods sold.

We believe we have several attractive opportunities to continue to grow our transmix, wholesale, terminaling and other operations. We are seeking to enter into contracts for additional transmix supplies, which we could process using existing excess capacity. While our Dallas-Fort Worth facility runs its transmix tower at or near capacity, our Birmingham transmix tower, which is the newest transmix tower in the United States, was running at half of its design capacity at the end of 2013. In addition, we believe that our transmix business model can be replicated successfully in other regions of the United States, and we actively evaluate potential acquisitions of bulk fuel terminals that have similar characteristics to our existing operations in Texas and Alabama. We also continue to seek additional terminaling customers, and regularly analyze our wholesale customers to maximize profitability.

Dallas-Fort Worth Facility

At our Dallas-Fort Worth facility, we offer our customers a diverse, high-quality product mix, including conventional gasoline and low sulfur diesel from our transmix processing and ultra-low sulfur diesel from bulk purchases. Low sulfur diesel contains no more than 500 parts per million, or ppm, of sulfur, and it is used primarily for locomotives, marine and off-road equipment used in agriculture, mining, power generation and construction. Ultra-low sulfur diesel, which began replacing low sulfur diesel in 2006 for on-highway applications, contains no more than 15 ppm of sulfur. Ultra-low sulfur diesel meets Environment Protection Agency ("EPA") standards for on-highway diesel fuel sold at retail locations in the United States and can also be used in all on or off-road applications.

Our Dallas-Fort Worth facility is strategically located in the Dallas-Fort Worth metropolitan area on approximately 20 acres of land that we own and provides us access to an attractive market for our fuel products and direct connections to third-party refined products pipelines directly serving our transmix processing units and adjacent storage tanks. Specifically, we can receive transmix and bulk fuel product via three different pipelines at our Dallas-Fort Worth facility: the 28-inch and 10-inch pipelines owned by Explorer Pipeline Company and a major independent refiner's proprietary products pipeline. The 10-inch Explorer and independent refiner's pipelines terminate within a mile of our Dallas-Fort Worth facility. Additionally, we can receive inbound product via truck.

We own two transmix processing units at our Dallas-Fort Worth facility. These transmix processors were constructed in 1996 and 2003 and have a combined processing capacity of approximately 7,000 barrels of transmix per day. We purchased and refurbished our second processor in 2005. We sold an average of 4,065 barrels per day of refined products processed from transmix during the year ended December 31, 2013.

We purchase an average of nearly 22,000 barrels of ultra-low sulfur diesel each month under short-term purchase contracts. In addition, we receive tolling fees from one customer who stores its own refined fuel products at our terminal.

We have 49 storage tanks at our Dallas-Fort Worth facility with total storage capacity of approximately 250,000 barrels. Additionally, we lease approximately 25,000 barrels of storage space at a fuel terminal that is connected to us by pipeline. While we continually strive to minimize inventory, our significant storage capacity provides us with the ability to receive large inbound batches of transmix from our transmix suppliers and allows us to offer our customers a wide range of fuel products.

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We are able to distribute our fuel products efficiently through a truck rack at our Dallas-Fort Worth facility that is connected to our storage tanks. Our two-lane truck rack has a maximum daily capacity of 144 full-sized tank-trucks with an average utilization of 84 trucks per day. The truck rack at our Dallas-Fort Worth facility is fully automated so that drivers can quickly and easily select the specific blend of fuel that meets their needs.

Birmingham Facility

At our Birmingham facility, we also offer our customers a diverse, high-quality product mix, including conventional gasoline and low sulfur diesel from our transmix processing as well as gasoline and ultra-low sulfur diesel in connection with our wholesale fuel distribution operations. In addition, we provide a suite of complementary fuel products and services, including third-party terminaling, renewable fuel blending and reclamation services.

Our Birmingham facility is strategically located on approximately 40 acres of land that we own and provides us access to an attractive market for our fuel products and direct connections to third-party refined product pipelines directly serving our transmix processing units and adjacent storage tanks. Specifically, we can receive transmix and bulk fuel product via spurs from the Colonial and Plantation Pipelines. Additionally, we can receive inbound product via truck.

We own one transmix processing unit at our Birmingham facility that has a processing capacity of approximately 5,000 barrels of transmix per day. This unit was constructed and placed in service during 2009. We sold an average of approximately 1,925 barrels per day of refined products processed from transmix at this facility during the year ended December 31, 2013.

We have 44 storage tanks at our Birmingham facility with total storage capacity of approximately 523,000 barrels, which is one of the largest volumes of storage capacity of any market participant in Birmingham, Alabama. While we continually strive to minimize inventory, our significant storage capacity provides us with the ability to receive large inbound batches of transmix from our transmix suppliers and wholesale bulk purchases, which allows us to offer our customers a wide range of fuel products in connection with our wholesale fuel distribution operations.

We are able to distribute our fuel products efficiently through a truck rack that is connected to our storage tanks. Our Birmingham facility's four-lane truck rack has a maximum daily capacity of 384 full-sized tank-trucks with an average utilization of approximately 100 trucks per day. In addition to gasoline and diesel, we also offer our customers biodiesel, ethanol and other additive blending at the rack. The terminal and truck rack at our Birmingham facility are fully automated so that drivers can quickly and easily select the specific blend of fuel that meets their needs. Pursuant to month- to-month contracts with several of our customers, we also receive tolling fees on their gasoline and diesel that are sold across our truck rack.

In December 2012, we placed an idled biodiesel refinery at our Birmingham facility back into service and began commercial sales. Biodiesel contains no petroleum products and can be blended with petroleum-based diesel to create a biodiesel blend. Biodiesel is a clean-burning fuel that produces approximately 80% lower greenhouse gas emissions than petroleum diesel when each is separately combusted. Large refining companies are required to blend biodiesel with a portion of their ultra-low sulfur diesel or to purchase and retire a comparable volume of RINs. It is generally more economical to purchase and blend biodiesel than to purchase and retire RINs. This refinery has a practical capacity of producing approximately 2 million gallons of biodiesel fuel annually, and produced 1.2 million gallons during the year ended December 31, 2013.

We also operate equipment at our Birmingham facility that allows us to offer customers a unique alternative for the disposal of refined petroleum tank bottoms and petroleum contact waters ("PCW"). By reclaiming fuels from these wastes and placing them back into fuel service, our reclamation services

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eliminate the need for hazardous waste disposal. We also have 17 petroleum tank trailers and 13 vacuum trucks, which enable us to assist in tank cleanings and PCW transportation that range in size and scope.

Corporate

Certain items are reviewed by our management on a consolidated basis, and are therefore presented as corporate operations rather than segment operations:

•

general and administrative costs related to corporate overhead, such as headquarters facilities and personnel, as well as equity-based compensation;



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certain other operating costs such as IPO transaction-related; and



•

non-operating items such as interest, other income and income taxes.

Customers

Sand

We sell substantially all of the sand we produce to customers in the oil and gas proppants market. Our customers include major oilfield services companies that are engaged in hydraulic fracturing. Sales to the oil and gas proppants market comprised approximately 99% of our total Sand segment sales in 2013.

In 2013, 93% of our sales were under long-term contracts, and 51% of our total sand sales were sales in excess of the contracted minimums with these customers. As of December 31, 2013, we have 1.3 million tons under long-term contract with a weighted average remaining term of 2.8 years. Of the product we have under long-term contract, 63% is under take-or-pay contract, 19% is under a fixed-volume contract, and 18% is under an efforts-based contract. All three of these contracts have minimum volumes that the customer must purchase from us at an agreed-upon price. If a customer fails to perform under these contracts, each contract type has a different remedy: under take-or-pay, there is a specific remedy stated in the contract's liquidated damages clause; under a fixed-volume or efforts-based contract, damages are usually determined in arbitration. Efforts-based contracts also have certain market-out clauses wherein a customer may be relieved of his purchase obligation if he is unable to re-sell or use the sand because of adverse market conditions, such as a moratorium on the use of raw sand to fracture-stimulate a hydrocarbon well.

In 2013, our two largest customers represented 35% and 21% of our total sand sales for the year ended December 31, 2013.

Due to recent expansions in the supply of frac sand and processing capacity and the expectation of continued expansions, we believe that frac sand customers are increasingly reluctant to enter into take-or-pay contracts that expose them to pre-determined financial liability for failure to take delivery of minimum volumes of frac sand. Customers increasingly pursue efforts-based contracts over take-or-pay or fixed-volume contracts, and tend to contract at significantly lower levels than they ultimately plan to purchase. We also believe customers will be increasingly focused upon the relative quality of sand reserves, logistics capabilities and service level provided by the frac sand provider. As a consequence, we believe that we will be able to secure significant orders from customers over and above their contract minimums.

We believe that we will continue to sell a significant portion of our uncontracted tons to contract customers, and we will continue to seek additional long-term contracts with both existing contract customers and customers who are currently purchasing sand through a purchase order or spot basis. In the event that one or more of our current contract customers decides not to continue purchasing our frac sand following the expiration of its contract with us, we believe that we will be able to sell the volume of sand that they previously purchased to other customers through long-term contracts or sales on the spot market. We also intend to continue in our efforts to diversify our customer base. During the year ended December 31, 2013, we converted two customers from purchase order-only to contract customers and added nine new customers.

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Fuel

Our primary fuel processing and distribution markets are the Dallas-Fort Worth metropolitan area and Birmingham, Alabama. Combined, these markets contain approximately 6.4 million people.

We are a key seller to unbranded retailers and petroleum wholesalers, and act as a key supplier of terminaling services to various fuel refiners and large fuel marketing companies. The unbranded gasoline market has seen high growth in recent years due to a decline in the willingness of consumers to pay a premium for branded fuel. Many unbranded retailers have difficulty purchasing from the major distributors due to the restrictive supply relationship between such distributors and their franchised retailers. As unbranded retailers have expanded in recent years, we have acted as a key supplier to this market. We have capitalized on supplying the unbranded gasoline market because only limited quantities of unbranded fuel are stored in the regions in which we operate. However, we also believe it is advantageous to serve branded gasoline customers as well, and our fuel additive systems that were installed in 2013 give us the ability to serve both the branded and unbranded markets going forward.

Suppliers and Service Providers

Sand

We believe frac sand companies differentiate themselves, from a cost and service perspective, based on their ability to wash, screen, dry and ship product efficiently. Mineral extraction is an important component of frac sand operations, but is viewed as a less differentiated skill set that can be performed efficiently by specialized third party providers. We mine our own frac sand reserves at our Kosse facility, and have engaged a mining expert to manage excavation activities at our Wisconsin facilities.

In 2012, we entered into a ten-year wet sand supply contract with Midwest Frac pursuant to which we are obligated to purchase at least 200,000 tons of wet sand per year and have the right to purchase an annual allotment of up to 500,000 tons of annual wet sand production from a deposit near our Barron facility. We have also engaged Fred Weber to mine and process wet sand at our New Auburn wet plant facility under a contract that expires in 2016, at which time title and operations of the facility will revert to us.

Fuel

We purchase transmix from pipeline or terminal operators, primarily under contractual arrangements that benefit us and our suppliers. Generally, we structure our supply contracts so that we receive all of our suppliers' transmix volume, regardless of regulatory changes, expansions of operations, higher utilization rates or other factors that may increase their supply. This helps assure our suppliers that their transmix will be removed on a timely basis so that their operations will not be interrupted. Major refineries prefer not to process transmix because it is less economical than processing crude oil due to the relatively lower volumes, decreased efficiency and concerns associated with the impact that fuel additives may have on expensive catalysts. We enable refiners to remain focused on crude oil processing by providing an economical and reliable solution for their transmix processing.

We currently purchase approximately 72% of our supply of transmix pursuant to exclusive contracts with terms ranging from 12 to 48 months, with a volume-weighted average remaining duration of seven months as of December 31, 2013. We purchase approximately 23% of our supply of transmix pursuant to contracts whereby our suppliers have the option of shipping product to alternative transmix processors. The remainder of our supply of transmix is purchased on a spot basis. For the year ended December 31, 2013, our two largest suppliers of transmix accounted for approximately 30% and 26% of our total transmix purchases. The contract with our largest supplier for 2013 expires on December 31, 2014 and the contract with our second largest supplier expires on September 30, 2014.

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We receive transmix by truck and pipeline, depending upon the geographic location of each of our supply points. In general, truck shipments are more expensive but they allow us to receive small batches on a frequent basis. As a result, truck receipts are generally lower margin than pipeline receipts but inventory requirements are minimal. Conversely, pipeline shipments generally have to be aggregated to make shipments that meet minimum batch sizes for pipeline companies but the transportation cost is lower than for truck shipments.

Our wholesale fuel suppliers include major oil companies that ship us wholesale fuel via scheduled pipeline tenders or through in-tank transfers at our Birmingham facility.

Competition

Sand

The frac sand market is a highly competitive market that is comprised of a small number of large, national producers and a larger number of small, regional or local producers. Competition in the frac sand industry has increased in recent years due to favorable pricing and demand trends, and we expect competition to continue to increase if those trends continue. Suppliers compete based on price, consistency and 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 are one of the four leading producers of frac sand in 2013 including Unimin Corporation, Fairmount Minerals, Ltd., U.S. Silica Holdings, Inc., and SSS. In recent years there has also been an increase in the number of small producers servicing the frac sand market due to an increased demand for hydraulic fracturing services and related proppant supplies. Due to this increased demand, existing or new frac sand producers could expand their frac sand production capacity, thereby increasing competition. We believe, however, that the relative inexperience of many management teams operating in the frac sand industry coupled with the costs, length of time and operational challenges associated with identifying attractive frac sand reserves, obtaining necessary permits and regulatory approvals and constructing a sand processing facility has prevented these smaller competitors from capitalizing in the market on a long-term basis. Further, the large capital requirements to locate storage and transload facilities into the various North American shale plays creates a significant additional barrier to entry for those considering whether to enter the market. We believe that industry consolidation and the exit from the market by less successful competitors will continue in the near term and should benefit the pricing environment for SSS and the remaining frac sand producers.

Fuel

We are the only transmix processor operating in the Dallas-Fort Worth and Birmingham markets. In general, transmix shipped by truck is less competitive than transmix shipped by pipeline, and these logistical considerations typically lead a transmix producer to the conclusion that there is only one appropriate location for processing its transmix in a geographic region. In cases where transmix can be transported economically by pipeline to several different transmix processing locations, the level of competition is significantly greater. In addition to price, suppliers of transmix also consider storage capacity, which minimizes the risk that transmix will not be removed on a timely basis, financial strength and operational history when evaluating potential transmix processors.

We compete with other wholesale distributors of refined products in our markets. Our competitors include large, integrated, major or independent oil companies operating in our markets. Because these competitors have more diverse operations and stronger capitalization, they may be better positioned than we are to withstand changing industry conditions, including shortages or excesses of petroleum products or intense price competition at the wholesale level.

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Fuel terminal customers make their purchasing decisions based on several criteria. The most important criteria are price, location, service and product breadth/consistency. The price of fuel is generally a customer's primary focus, but that price must also take into account the cost of transportation. Terminals closer to sub-markets that are the largest consumers of fuel have an economic advantage over more remote terminals. Our Dallas-Fort Worth terminal is centrally located so we can economically serve most major sub-markets in Dallas-Fort Worth. Our Birmingham terminal is located in the same area as all other major fuel terminals in the market. The most important elements in providing quality service to terminal customers are speed of throughput and efficient back-office operations. Customers rarely have to wait to load at our truck racks, given our significant excess rack capacity. We also believe we have a system that provides us with a high degree of accuracy when billing our customers. Additionally, a broad product offering is important because customers generally prefer to be able to obtain multiple types of fuel from one supplier. Finally, our customers prefer suppliers who are capable of providing product every day. The addition of wholesale product to supplement the products resulting from our own transmix processing operations provides us with a broad product line for our core customers and makes it more likely that we will have product available for sale every day.

Seasonality

Because raw sand cannot be wet-processed during sub-zero 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 to feed the dry plant during the winter months, causing the average inventory balance to increase from a few weeks in early spring to more than 100 days in early winter and resulting in seasonal variations in our cash flow. We may also be selling 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 volumes sold and segment 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.

Our Fuel operations have not historically reflected any material seasonality. However, as we do hold refined petroleum products in our terminals and may take title to the product as it is shipped to our terminals, we expect to experience marginally higher earnings in periods where refined product prices are in contango, and marginally lower earnings in periods where refined product prices are in backwardation.

Insurance

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

Environmental and Occupational Health and Safety Regulations

We are subject to stringent and complex federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of worker health, safety and the environment. These regulations include compliance obligations for air emissions, water quality, wastewater discharges and solid and hazardous waste disposal, as well as regulations designed for the protection of worker health and safety and threatened or endangered species. Compliance with these environmental laws and regulations may expose us to significant costs and liabilities and cause us to incur

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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. While we believe that our operations are in substantial compliance with applicable environmental laws and regulations and that continued compliance with current requirements would not have a material adverse effect on us, there is no assurance that this degree of compliance will continue in the future. In addition, the clear trend in environmental regulation is to place more restrictions on activities that may affect the environment, and thus, any changes in, or more stringent enforcement of, these laws and regulations that result in more stringent and costly pollution control equipment, waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our operations and financial position.

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. We cannot assure you, however, that future events, such as changes in existing laws or enforcement policies, the promulgation of new laws or regulations or the development or discovery of new facts or conditions adverse to our operations will not cause us to incur significant costs. The following is a discussion of material environmental and worker health and safety laws that relate to our operations. We believe that we are in substantial compliance with all of these environmental laws and regulations.

Air emissions.    Our operations are subject to the Clean Air Act, as amended (the "CAA"), and comparable state and local laws, which restrict the emission of air pollutants from many sources and also impose various monitoring and reporting requirements. 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. Amendments to the CAA, including, among others, the CAA Amendments of 1990, require most industrial operations in the United States to incur capital expenditures to meet the air emission control standards that are developed and implemented by the EPA and state environmental agencies. 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. Moreover, facilities that emit volatile organic compounds or nitrogen oxides face increasingly stringent regulations, including requirements to install various levels of control technology on sources of pollutants. In addition, the petroleum processing sector is subject to stringent and evolving EPA and state regulations that establish standards to reduce emissions of certain listed hazardous air pollutants. While the hazardous air pollutant emissions from our facilities are below the threshold levels for the stringent maximum achievable control technology, or MACT, standards to apply, our Dallas-Fort Worth facility is an "area source" subject to the less stringent generally achievable control technology standards for gasoline distribution terminals that were promulgated by EPA in January 2011. In addition, air permits are required for our processing and terminal operations, and 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. While we believe that we are in substantial compliance with the CAA and its implementing regulations, as well as similar state and local laws and regulations, frequently changing and increasingly stricter requirements, future non-compliance, or failure to maintain necessary permits or other authorizations could require us to incur substantial costs or suspend or terminate our operations.

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The CAA also requires states to draft State Implementation Plans ("SIPs") designed to attain national health-based ambient air quality standards ("NAAQS") in primarily major metropolitan and/or industrial areas. SIPs frequently regulate emissions from stationary sources such as our operations. The Dallas-Fort Worth area is currently in nonattainment with the ozone NAAQS. We believe that we are in substantial compliance with applicable SIP requirements. New regulations designed to bring the Dallas-Fort Worth area into attainment with the ozone NAAQS were adopted by the Texas Commission on Environmental Quality (the "TCEQ") in late 2011. We believe, based upon the adopted regulations, that no material capital expenditures beyond those currently contemplated and no material increase in costs are likely to be required.

The CAA authorizes the EPA to require modifications in the formulation of the refined transportation fuel products we manufacture in order to limit the emissions associated with the fuel product's final use. For example, in December 1999, the EPA promulgated regulations limiting the sulfur content allowed in gasoline. These regulations required the phase-in of gasoline sulfur standards beginning in 2004, with special provisions for small refiners and for refiners serving those Western states exhibiting lesser air quality problems and, more recently, the EPA finalized on March 3, 2014, rules to further reduce the sulfur content of gasoline beginning in 2017. Similarly, the EPA promulgated regulations that limited the sulfur content of on-road diesel fuel beginning in 2006 from its current level of no more than 500 ppm to no more than 15 ppm. A portion of our transmix consists of jet fuel, which currently is not subject to the EPA regulations that limit the sulfur content of most categories of motor fuels. However, the sulfur content of various types of diesel fuel is subject to a decreasing series of sulfur concentration limits, for example a 15 ppm maximum sulfur concentration in all categories of diesel fuel except for locomotive and marine diesel that is sold after May 31, 2014. If the transmix we receive after May 2014 contains sufficient quantities of jet fuel, the sulfur content of the diesel fuel we produce from our transmix may exceed the 15 ppm level and, if it does, we will be prohibited from marketing this fuel for any uses other than locomotive or marine, or for any use within the Northeast and Mid-Atlantic regions of the United States. Further, as EPA emissions standards for locomotives grow more stringent through 2020, certain locomotives will be required to move to lower sulfur diesel, limiting sales of diesel with sulfur above 15 ppm to certain old locomotives and marine sources only.

On August 16, 2012, the EPA published final rules that establish new air emission controls and practices for oil and natural gas production wells, including wells that are the subject of hydraulic fracturing operations and natural gas processing operations. These rules will require, among other things, the reduction of volatile organic compounds from certain natural gas wells through the use of reduced emission completions or "green completions" in all hydraulically fractured or re-fractured wells after January 1, 2015. For subject well completion operations occurring at such well sites before January 1, 2015, the final regulations will allow operators to capture and direct flowback emissions to completion combustion devices, such as flares in lieu of performing green completions. These regulations also establish specific new requirements regarding emissions from dehydrators, storage tanks and other production equipment. The EPA later updated the storage tank standards on August 5, 2013 to phase in emission controls more gradually. Compliance with these rules could result in significant costs to our customers, which may have an indirect adverse impact on our business.

The CAA also requires an increasing percentage of vehicle fuels to come from renewable sources, including biodiesel. The regulations implementing this "Renewable Fuel Standard" or RFS, may be adjusted by the EPA administrator, or reduced or eliminated as a result of litigation challenging the RFS, if sufficient quantities of renewable fuels are not available. Uncertainty surrounding the potential for the EPA or a court to lower the standards for biodiesel or other renewable fuels could affect 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.

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Climate change.    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 is beginning to adopt regulations controlling GHG emissions under its existing authority under the CAA. For example, on December 15, 2009, the EPA officially published its findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth's atmosphere and other climatic changes. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the CAA. In 2009, the EPA adopted rules regarding regulation of GHG emissions from motor vehicles. In addition, on September 22, 2009, the EPA issued a final rule requiring the reporting of GHG emissions in the United States beginning in 2011 for emissions occurring in 2010 from specified large GHG emission sources. On November 30, 2010, the EPA published a final rule expanding its existing GHG emissions reporting rule for certain petroleum and natural gas facilities that emit 25,000 metric tons or more of carbon dioxide equivalent per year. The rule, which went into effect on December 30, 2010, requires reporting of GHG emissions by such regulated facilities to the EPA by September 2012 for emissions during 2011 and annually thereafter. In 2010, the EPA also issued a final rule, known as the "Tailoring Rule," that makes certain large stationary sources and modification projects subject to permitting requirements for GHG emissions under the CAA. Several of the EPA's GHG rules are being challenged in court and, depending on the outcome of these proceedings, such rules may be modified or rescinded or the EPA could develop new rules.

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.

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 state waters or waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. 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 navigable 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. We believe we are in substantial compliance with the CWA and similar state laws.

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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 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 and Congress continues to consider legislation to amend the SDWA. 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 commenced a multi-year study of the potential environmental impacts of hydraulic fracturing, with initial results released in December of 2012 and final results expected to be available by 2014 and, more recently, the EPA has announced that it will develop effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities by 2014. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior (the "DOI"), are evaluating various other aspects of hydraulic fracturing, with the DOI announcing draft proposed rules on May 4, 2012 that, if adopted, would 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 but subsequently announcing on January 18, 2013, that it will issue a revised draft proposal in replacement of the May 2012 draft in 2013. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms. The EPA also has announced that it believes hydraulic fracturing using fluids containing diesel fuel can be regulated under the SDWA notwithstanding the SDWA's general exemption for hydraulic fracturing and, more recently on May 4, 2012, the EPA issued draft guidance for SDWA permits issued to oil and natural gas exploration and production operators using diesel fuel during hydraulic fracturing. 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 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 management and disposal of hazardous and non-hazardous waste. These laws and regulations govern the generation, storage, treatment, transfer and disposal of wastes that we generate including, but not limited to, used oil, antifreeze, filters, sludges, paint, solvents and sandblast materials. 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

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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 subsidiaries operating within the Fuel segment. The Notice provides that the subsidiary may have incurred liability with respect to the Reef Environmental site in Alabama, and requested certain information in accordance with Section 107(a) of CERCLA. The subsidiary 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 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. While some of our facilities may be located in areas that are designated as habitats for endangered or threatened species, we believe that we are in substantial compliance with the ESA. However, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans or limit future development activity in the affected areas. Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia on September 9, 2011, the U.S. Fish and Wildlife Service is required to consider listing more than 250 species as endangered under the Endangered Species Act. Under the September 9, 2011 settlement, the U.S. Fish and Wildlife Service 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 designation of previously unprotected species as threatened or endangered in areas where our exploration and production customers operate could cause us or our customers to incur increased costs arising from species protection measures and could result in delays or limitations in our customers' performance of operations, which could reduce demand for our services.

Mining and Workplace Safety.    Our sand mining operations are subject to mining safety regulation. The U.S. Mine Safety and Health Administration ("MSHA") is the primary regulatory organization governing the frac sand industry. Accordingly, MSHA regulates quarries, surface mines, underground mines and the industrial mineral processing facilities associated with quarries and mines. The mission of MSHA is to

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administer the provisions of the Federal Mine Safety and Health Act of 1977 and to enforce compliance with mandatory worker safety and health standards. MSHA works closely with the Industrial Minerals Association, a trade association in which we have a significant leadership role, in pursuing this mission. As part of MSHA's oversight, representatives perform at least two unannounced inspections annually for each aboveground facility. To date these inspections have not resulted in any citations for material violations of MSHA standards.

We also are subject to the requirements of the U.S. Occupational Safety and Health Act ("OSHA"), and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA Hazard Communication Standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and the public. OSHA regulates the customers and users of frac sand and provides detailed regulations requiring employers to protect employees from overexposure to silica through the enforcement of permissible exposure limits and the OSHA Hazard Communication Standard.

Local Regulation.    As demand for frac sand in the oil and natural gas industry has driven a significant increase in current and expected future production of frac sand, some local communities have expressed concern regarding silica sand mining operations. These concerns have generally included exposure to ambient silica sand dust, truck traffic, water usage and blasting. In response, certain state and local communities have developed or are in the process of developing regulations or zoning restrictions intended to minimize dust from becoming airborne, control the flow of truck traffic, significantly curtail the amount of practicable area for mining activities, provide compensation to local residents for potential impacts of mining activities and, in some cases, ban issuance of new permits for mining activities. To date, we have not experienced any material impact to our existing mining operations or planned capacity expansions as a result of these types of concerns. We are not aware of any proposals for significant increased scrutiny on the part of state or local regulators in the jurisdictions in which we operate or community concerns with respect to our operations that would reasonably be expected to have a material adverse effect on our business, financial condition or results of operations going forward.

Employees

We have no employees. All of our management, administrative and operating functions are performed by employees of Emerge Energy Services GP, LLC, which is our general partner. As of December 31, 2013, our general partner employed 190 full-time employees who provide these services for us. None of these employees are subject to collective bargaining agreements. We consider our employee relations to be good.

Available Information

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

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

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ITEM 1A.        RISK FACTORS

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

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

Risks Related to Our Business

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

We may not have sufficient available cash each quarter to enable us to pay any distributions to our unitholders. Furthermore, our partnership agreement does not require us to pay distributions on a quarterly basis or otherwise. The amount of cash we can distribute to our unitholders principally depends upon the amount of cash we generate from our operations, which fluctuates from quarter to quarter based on, among other things:

•

the level of production of, demand for, and price of frac sand and oil, natural gas, gasoline, diesel, biodiesel and other refined products, particularly in the markets we serve;



•

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



•

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



•

the level of competition from other companies;



•

the cost and time required to execute organic growth opportunities;



•

difficulty collecting receivables; and



•

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

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

•

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



•

the level of our operating costs and expenses;



•

our debt service requirements and other liabilities;



•

fluctuations in our working capital needs;



•

restrictions contained in our revolving credit facility and other debt agreements to which we are a party;



•

the cost of acquisitions, if any;

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•

fluctuations in interest rates;



•

our ability to borrow funds and access capital markets; and



•

the amount of cash reserves established by our general partner.

Our partnership agreement does not require us to pay a minimum quarterly distribution. 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 quarterly distributions, if any, are subject to significant fluctuations based on the above factors.

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

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

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 are directly dependent on the performance of our business. Because our quarterly distributions will significantly correlate to the cash we generate each quarter after payment of our fixed and variable expenses, quarterly distributions paid to our unitholders may vary significantly from quarter to quarter and may be zero.

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

The board of directors of our general partner adopted a cash distribution policy pursuant to which we distribute all of the available cash we generate each quarter to unitholders of record on a pro rata basis. However, the board may change such policy at any time at its discretion and could elect not to make distributions for one or more quarters. 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.

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 and refined fuel 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, and natural gas prices have continued to be low through the second quarter of 2012. Worldwide economic, political and military events, including war, terrorist activity, events in the Middle East and initiatives by the Organization of the Petroleum Exporting Countries have contributed, and are likely to continue to contribute, to commodity price volatility. Additionally, warmer

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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, 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. Similarly, demand for our refined fuel products is lower during times of economic slowdown. 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 or other factors, could have a material adverse effect on our business, even in a stronger natural gas and oil price environment.

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

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

•

changes in the price and availability of transportation;



•

inability to obtain necessary production equipment or replacement parts;



•

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



•

unusual or unexpected geological formations or pressures;



•

unanticipated ground, grade or water conditions;



•

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



•

labor disputes and disputes with our excavation contractors;



•

late delivery of supplies;



•

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



•

technical difficulties or failures;



•

cave-ins or similar pit wall failures;



•

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



•

industrial accidents;



•

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



•

inability of our customers or distribution partners to take delivery;



•

reduction in the amount of water available for processing;

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•

fires, explosions or other accidents; and



•

facility shutdowns in response to environmental regulatory actions.

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

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

A large portion of our sales in each of our Sand segment and our Fuel segment 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 2013, our top five Sand customers represented 81.7% of sales from our Sand operations. During 2013, our top five Fuel customers represented 37.3% of sales from our Fuel operations. In our Fuel segment, we derive a significant portion of our revenues from sales to contract customers and the terms of our contracts are typically for one year or less. 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 Sand 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 three of our largest customers contain provisions designed to compensate us, in part, for our lost margins on any unpurchased volumes; accordingly, in such 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.

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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.

Certain of our contracts contain provisions requiring us to purchase or deliver minimum amounts of sand. 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 amount of tonnage contracted for and the amount delivered. Our agreement with Canadian National requires us to provide minimum volumes of frac sand for shipping on the Canadian National line. If we do not provide the minimum volume of frac sand for shipping, we will be required to pay a per-ton shortfall penalty, subject to certain exceptions. In addition, under our agreement with Midwest Frac, we are obligated to purchase a minimum annual volume of 200,000 tons of wet sand from Midwest Frac's mine or pay a fee to Midwest Frac with respect to the volumes we do not purchase up to 200,000 tons. Finally, under our agreement with Fred Weber, we are obligated to order a minimum of 300,000 tons of wet sand per year produced by Fred Weber or pay fees on the difference between 300,000 tons and the amount we actually order. If we are unable to meet our obligations under any of these agreements, we may have to pay substantial penalties or the agreements may become subject to termination, as applicable. In such events, our business, financial condition and results of operations may be materially adversely affected.

We 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.

Frac sand is a proppant used in the completion and re-completion of natural gas and oil wells through the process of hydraulic fracturing. Frac sand is the most commonly used proppant and is less expensive than ceramic and resin coated proppants, which are also used in the hydraulic fracturing process to stimulate and maintain oil and natural gas production. A significant shift in demand from frac sand to other proppants, such as resin coated sand and ceramic alternatives, could have a material adverse effect on our business, financial condition and results of operations. In addition, 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. In addition, under our agreement with Midwest Frac, we are obligated to purchase a minimum of 200,000 tons of wet sand per year from a deposit near our Barron County facility over a 10-year period. Finally, under our agreement with Fred Weber, Inc., we are obligated to order a minimum of 300,000 tons of wet sand per year produced by Fred Weber or pay fees on the difference between 300,000 tons and the amount we actually order. A reduction in demand for the frac sand we produce may cause these contractual arrangements to become economically unattractive and could have a material adverse effect on our business, financial condition and results of operations.

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Fuel prices and costs are volatile, and we have unhedged commodity price exposure between the time we purchase fuel supplies and the time we sell our product that may reduce our profit margins.

Our financial results from our Fuel segment are strongly affected by the relationship, or margin, between the prices we charge our customers for fuel and the prices we pay for transmix, wholesale fuel and other feedstocks. We purchase our transmix, wholesale fuel and other feedstocks based on several different regional refined product price indices, the most important of which are the Platts Gulf Coast gasoline and diesel price postings. The costs of our purchases are generally set on the day that we purchase the products. We typically sell our fuel products within 7 to 10 days of our supply purchases at then prevailing market prices; however, the length of time that we hold inventory may increase due to events beyond our control, such as adverse economic conditions or a slowdown in pipeline transit times. During the period we have title to products that are held in inventory for processing and/or resale, we will be exposed to commodity price risk. Furthermore, the longer our fuel products remain in our inventory, the greater our exposure to commodity price risk. If the market price for our fuel products declines during this period or generally does not increase commensurate with any increases in our supply and processing costs, our margins will fall and the amount of cash we will have available for distribution will decrease. In addition, because our inventory is valued at the lower of cost or market value, if the market value of our inventory were to decline to an amount less than our cost, we would record a write-down of inventory and a non-cash charge to cost of sales. In a period of decreasing transmix or refined product prices, our inventory valuation methodology may result in decreases in our reported net income and cash available for distribution to unitholders.

We also follow a financial hedging program whereby we hedge a portion of our gasoline and diesel inventory, which is intended to reduce our commodity price exposure on some of our activities in our Fuel segment. Even though we enter into hedging arrangements to reduce our commodity price exposure, we cannot guarantee that such arrangements will provide sufficient price protection or that our counterparties will be able to perform under them, such as in the case of a counterparty's insolvency.

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

The performance, quality and safety of our products are critical to the success of our business. For instance, our frac sand must meet stringent International Organization for Standardization, or ISO, and API technical specifications, including sphericity, grain size, crush resistance, acid solubility, purity and turbidity, as well as customer specifications, in order to be suitable for hydraulic fracturing purposes. If our frac sand fails to meet such specifications or our customers' expectations, we could be subject to significant contractual damages or contract terminations and face serious harm to our reputation, and our sales could be negatively affected. The performance, quality and safety of our products depend significantly on the effectiveness of our quality control systems, which, in turn, depends on a number of factors, including the design of our quality control systems, our quality-training program and our ability to ensure that our employees adhere to our quality control policies and guidelines. Any significant failure or deterioration of our quality control systems could have a material adverse effect on our business, financial condition, results of operations and reputation.

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

Because of the relatively low cost of producing frac sand, transportation and handling costs tend to be a significant component of the total delivered cost of sales. The bulk of our currently contracted sales involve our customers also contracting with truck and rail services to haul our frac sand to end users. If there are increased costs under those contracts, and our customers are not able to pass those increases along to end users, our customers may find alternative providers. Recently, we have begun providing fee-based, transportation and logistics (including railcar procurement, freight management and product storage)

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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. A significant increase in transportation service rates, a reduction in the dependability or availability of transportation services 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.

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 and refined products 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 competitors in the refined products industry include large, integrated, major or independent oil companies that, because of their more diverse operations and stronger capitalization, may be better positioned than we are to withstand volatile industry conditions, including shortages or excesses of crude oil, transmix or refined products or intense price competition at the wholesale level. Additionally, the two largest processors of transmix have substantial financial and operational resources. These processors may choose to invest in additional transmix processing capacity and compete with us directly in our core markets.

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 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

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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.

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 depend on certain transmix and wholesale fuels suppliers for a significant portion of our transmix and wholesale fuels, and the loss of any of these key suppliers or a material decrease in the supply of transmix or wholesale fuels generally available to us could materially reduce our ability to make distributions to unitholders.

We purchase transmix from major oil companies, brokers and local retailers in Texas and Alabama. We currently purchase approximately 72% of our supply of transmix pursuant to exclusive contracts with terms ranging from 12 to 48 months and a volume-weighted average remaining duration of approximately 7 months as of December 31, 2013. In addition, we have non-exclusive supply contract that represents approximately 23% of our transmix supply. This contract has a remaining duration of 12 months as of December 31, 2013. For the year ended December 31, 2013, our two largest suppliers of transmix accounted for 30% and 26% of our total transmix purchases. The contract with our largest supplier for the year ended December 31, 2013 expires in September 2014, and purchases from our second largest supplier are made pursuant to a month-to-month contract. To the extent that our suppliers reduce the volumes of transmix and wholesale fuels that they supply us as a result of declining production, other changes in refinery output or refining transportation and marketing strategies, competition or otherwise, or if our suppliers decide not to renew our supply contracts, our revenues, net income and cash available for distribution could decline unless we were able to acquire comparable supplies of transmix and wholesale fuels on comparable terms from other suppliers. In addition, our earnings would be adversely affected if a

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significant supply of transmix was no longer available due to refinery or pipeline closings or interruptions or other force majeure events.

We are dependent on certain third-party pipelines for transportation of our wholesale products, and if these pipelines become unavailable to us, our revenues and cash available for distribution could decline.

Our processing facilities in Texas and Alabama are each interconnected to two pipelines that supply all of our wholesale products. Additionally, we periodically receive transmix at our Texas facility on an additional pipeline. Since we do not own or operate any of these pipelines, their continuing operation is not within our control. If any of these third-party pipelines were to become partially or fully unavailable to transport products because of accidents, extreme weather conditions, government regulation, terrorism or other events, or if the rates or terms and conditions of service of any of these third-party pipelines were to change materially, our revenues, net income and cash available for distribution could decline.

Increases in the price of diesel fuel may adversely affect our results of operations.

Diesel fuel costs generally fluctuate with increasing and decreasing world crude oil prices, and accordingly are subject to political, economic and market factors that are outside of our control. Our operations are dependent on earthmoving equipment, railcars and tractor-trailers, and diesel fuel costs are a significant component of the operating expense of these vehicles. We contract with a third party industrial mining expert to excavate raw frac sand from our New Auburn mine, deliver the raw frac sand to our processing facility and move the sand from our wet plant to our dry plant, and pay a fixed price per ton of sand delivered to our wet plant, subject to a fuel surcharge based on the price of diesel fuel. Accordingly, increased diesel fuel costs could have an adverse effect on our results of operations and cash flows.

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

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

•

develop new business and enter into contracts with new customers;



•

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



•

identify and obtain additional frac sand reserves;



•

recruit and train qualified personnel and retain valued employees;



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expand our geographic presence;



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



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consummate accretive acquisitions;



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



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meet customer-specific contract requirements or pre-qualifications;



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



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

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If we do not achieve our expected growth, we may not be able to achieve our estimated results and, as a result, we would not be able to pay the estimated annual distribution, in which event the market price of our common units will likely decline materially.

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

From time to time, we may choose to make business acquisitions to pursue market opportunities, increase our existing capabilities and expand into new areas of operations. While we have reviewed acquisition opportunities in the past and will continue to do so in the future, we have not actively pursued any acquisitions, and 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.

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

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

We have a $200 million revolving credit facility with outstanding borrowings of $93.8 million as of December 31, 2013. Our ability to incur additional debt is subject to limitations under our revolving credit facility. Our level of debt has important consequences to us, including the following:

•

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



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



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

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

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

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

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grant liens;



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incur additional indebtedness;



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engage in a merger, consolidation or dissolution;



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enter into transactions with affiliates;



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sell or otherwise dispose of assets, businesses and operations;



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materially alter the character of our business as conducted at the closing of this offering; and



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make acquisitions, investments and capital expenditures.

Furthermore, our revolving credit facility contains certain operating and financial covenants. Our ability to comply with the covenants and restrictions contained in the revolving credit facility may be affected by events beyond our control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If we violate any of the restrictions, covenants, ratios or tests a significant portion of our indebtedness may become immediately due and payable, our lenders' commitment to make further loans to us may terminate, and we will be prohibited from making distributions to our unitholders. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. Any subsequent replacement of our revolving credit facility or any new indebtedness could have similar or greater restrictions.

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

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

Additionally, our ability to hire, train and retain qualified personnel will continue to be important and will become more challenging as we grow and if energy industry market conditions continue to be positive. When general industry conditions are good, the competition for experienced operational and field technicians increases as other energy and manufacturing companies' needs for the same personnel 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.

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

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

•

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



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



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

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

Our Sand 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 processing, terminal 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, terminal, 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

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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.

There is inherent risk of incurring significant environmental costs and liabilities in the operation of our facilities due to our handling of petroleum hydrocarbons, biodiesel, ethanol and wastes, air emissions and water discharges related to our operations, and historical operations and waste disposal practices by prior owners and operators. We currently own or operate properties that for many years have been used for industrial activities, including processing or terminal storage operations. Petroleum hydrocarbons, hazardous substances or wastes have been released on or under the properties owned or operated by us. Joint and several strict liability may be incurred in connection with such releases of petroleum hydrocarbons and wastes on, under or from our properties and facilities. Private parties, including the owners or operators of properties adjacent to our operations and facilities where our petroleum hydrocarbons or wastes are taken for reclamation or disposal, 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 may not be able to recover some or any of these costs from insurance or other sources of indemnity.

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.

The effect of the renewable fuel standard program in the Energy Independence and Security Act of 2007 is uncertain.

The domestic market for biodiesel is largely dictated by federal mandates for blending renewable fuels with gasoline and diesel. The mandated level for biomass-based diesel for 2013 of 1.28 billion gallons under the RFS in the Energy Independence and Security Act of 2007 is higher than current domestic production levels. Future demand will be largely dependent upon the capacity available to meet the RFS, and the economic incentives to blend based upon the relative value of traditional diesel versus biomass-based diesel. Any significant increase in production capacity beyond the RFS level could have a negative impact on biodiesel prices. An administrative or court-ordered reduction or waiver of the RFS mandate could also negatively affect biodiesel prices and our future performance.

We may be unable to sell some of our transmix-derived diesel fuel in the off-road markets after mid-2014 because it may contain sulfur concentrations above levels allowed by EPA regulations.

In mid-2006, the EPA promulgated regulations requiring a reduction in the sulfur content of diesel fuel. Using a phased-in approach through 2014, these regulations will require that the maximum allowable sulfur content of diesel fuels used in a variety of off-road applications, excluding locomotive and marine uses, be reduced to 15 ppm (referred to as "ultra-low sulfur diesel"). The diesel fuel produced from our transmix operations is sold for use in off-road applications and will be subject to these phased-in regulations by May 2014, except for diesel fuel used in locomotive and marine applications outside of the Northeast and Mid-Atlantic regions of the United States. Because a portion of our transmix consists of jet fuel, which currently is not subject to EPA regulations limiting its maximum sulfur content, the diesel fuel produced from such transmix may exceed the 15 ppm level. In the event that diesel fuel produced from transmix exceeds the 15 ppm level, we would be prohibited after mid-2014 from marketing this fuel for any

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uses other than locomotive or marine outside of the Northeast and Mid-Atlantic regions. If this were to occur and we were forced to market our low sulfur diesel to locomotive or marine customers only in certain regions of the country, we would have to find new customers for our transmix diesel or find economic means of reducing sulfur levels, or stop sourcing higher sulfur transmix that is mixed with jet fuel. Further, changes in emissions regulations for locomotives will likely mean only marine customers will be able to use fuel that exceeds the 15 ppm level at some time between 2015 and 2020. There can be no assurance that we would be able to find sufficient marine customers without an adverse effect on our financial condition, results of operations, or ability to make distributions to our unitholders.

Our sales of petroleum products, and any related hedging activities, expose us to potential regulatory risks.

The Federal Trade Commission and the Commodity Futures Trading Commission hold statutory authority to regulate conduct in certain physical energy commodities markets and in markets for energy commodities futures, options on futures and swaps that may be relevant to our business. These agencies have imposed broad regulations prohibiting fraud and manipulation in the markets over which they have statutory authority. With regard to our physical sales of fuel products, and any related hedging activities, we may be required to observe the market-related regulations enforced by these agencies, which hold substantial enforcement authority. Failure to comply with such regulations, as interpreted and enforced, could materially and adversely affect our financial condition or results of operations.

Climate change legislation and regulatory initiatives 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, or 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 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 is beginning to adopt regulations controlling GHG emissions under its existing authority under the federal Clean Air Act, as amended, or the CAA. For example, on December 15, 2009, the EPA officially published its findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth's atmosphere and other climatic changes. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the CAA. In 2009, the EPA adopted rules regarding regulation of GHG emissions from motor vehicles. In addition, on September 22, 2009, the EPA issued a final rule requiring the reporting of GHG emissions in the United States beginning in 2011 for emissions occurring in 2010 from specified large GHG emission sources On November 30, 2010, the EPA published a final rule expanding its existing GHG emissions reporting rule for certain petroleum and natural gas facilities that emit 25,000 metric tons or more of carbon dioxide equivalent per year. The rule, which went into effect on December 30, 2010, requires reporting of GHG emissions by such regulated facilities to the EPA by September 2012 for emissions during 2011 and annually thereafter. In 2010, the EPA also issued a final rule, known as the "Tailoring Rule," that makes certain large stationary sources and modification projects subject to permitting requirements for GHG emissions under the CAA.

Although it is not currently possible to predict how any such proposed or future GHG legislation or regulation by Congress, 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

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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.

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.

The federal Safe Drinking Water Act, or the SDWA, regulates the underground injection of substances through the Underground Injection Control Program, or the UIC Program. Currently, with the exception of certain hydraulic fracturing activities involving the use of diesel, hydraulic fracturing is exempt from federal regulation under the UIC Program, and the hydraulic fracturing process is typically regulated by state or local governmental authorities. Although we do not directly engage in hydraulic fracturing activities, our oil and natural gas industry customers purchase our frac sand for use in their hydraulic fracturing operations. The EPA has taken the position that hydraulic fracturing with fluids containing diesel is subject to regulation under the UIC Program, specifically as "Class II" UIC wells and, on May 4, 2012, the EPA issued draft guidance for federal SDWA permits issued to oil and natural gas exploration and production operators using diesel during hydraulic fracturing activities. On August 16, 2012, the EPA published final rules that establish new air emission controls for oil and natural gas production and natural gas processing operations. The final rule requires new standards on certain hydraulically-fractured wells constructed or re-fractured after January 1, 2015. At the same time, the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities and released initial results in December 2012, a committee of the U.S. House of Representatives (the "House") has been conducting an investigation of hydraulic fracturing practices and a subcommittee of the Secretary of Energy Advisory Board (the "SEAB") of the U.S. Department of Energy was tasked with recommending steps to improve the safety and environmental performance of hydraulic fracturing. As part of these studies, the EPA, the House committee and the SEAB subcommittee have requested that certain companies provide them with information concerning the chemicals used in the hydraulic fracturing process. In other investigatory activities, the EPA has announced plans to propose standards for the treatment and discharge of waste

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water resulting from hydraulic fracturing by 2014 and the DOI, announced draft proposed rules on May 4, 2012 that, if adopted, would 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. The DOI published a supplemental notice of proposed rulemaking on May 24, 2013 which replaced the proposed rulemaking issued by the agency in May 2012. These studies and initiatives, depending on their results, could spur proposals to regulate hydraulic fracturing under the SDWA or otherwise. The SEAB subcommittee issued a preliminary report in August 2011 recommending, among other things, measures to improve and protect air and water quality, improvements in communication among state and federal regulators, reduction of diesel fuel in shale gas production, disclosure of fracturing fluid composition and the creation of a publicly accessible database organizing all publicly disclosed information with respect to hydraulic fracturing operations. Legislation is currently before Congress to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. If this or similar legislation becomes law, the legislation could establish an additional level of regulation that may lead to additional permitting requirements or other operating restrictions, making it more difficult to complete natural gas wells in shale formations. This could increase our customers' costs of compliance and doing business or otherwise adversely affect the hydraulic fracturing services they perform, which may negatively impact demand for our frac sand products.

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, Wyoming, Colorado, Arkansas, Louisiana, Michigan, Montana, Texas and Pennsylvania, among other states, 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 by affected 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

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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 refined products 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.

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Risks Inherent in an Investment in Us

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

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

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

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

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



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



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



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



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

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•

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



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



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



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



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



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



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

Our general partner limits its liability regarding our obligations.

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

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

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

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how to allocate business opportunities among us and its affiliates;



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whether to exercise its limited call right;



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

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



•

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

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

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

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

•

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



•

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



•

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



•

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



•

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



•

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



•

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



•

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

In connection with a situation involving a transaction with an affiliate or a conflict of interest, any determination by our general partner must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the conflicts committee and the board of directors of our general partner determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest satisfies either of the standards set forth in

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bullets three and four above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. In this context, members of the board of directors of our general partner will be conclusively deemed to have acted in good faith if it subjectively believed that either of the standards set forth in bullets three and four above was satisfied.

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

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

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

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

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

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

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

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

•

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



•

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



•

the ratio of taxable income to distributions may increase;



•

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



•

the market price of the common units may decline.

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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:

•

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



•

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

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

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

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

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

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

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

Tax Risks to Common Unitholders

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

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

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, 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 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. Because of widespread state budget deficits and other reasons, 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, members of the U.S. Congress propose and consider substantive changes to

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the existing federal income tax laws that affect publicly traded partnerships. Any proposed legislation could potentially affect us and may, if enacted, be applied retroactively. We are unable to predict whether any such legislation will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.

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

Because a unitholder is treated as a partner to whom we allocate taxable income which could be different in amount than the cash we distribute, a unitholder's allocable share of our taxable income is taxable to it, which may require the payment of federal income taxes and, in some cases, state and local income taxes, on its share of our taxable income even if it receives no cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.

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

The IRS has made no determination with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. 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 and our general partner because the costs will reduce our cash available for distribution.

We have a subsidiary that is treated as a corporation for federal income tax purposes and subject to corporate-level income taxes.

Even though we (as a partnership for U.S. federal income tax purposes) are not subject to U.S. federal income tax, some of our operations are currently conducted through a subsidiary that is organized as a corporation for U.S. federal income tax purposes. The taxable income, if any, of a subsidiary that is treated as a corporation for U.S. federal income tax purposes, is subject to corporate-level U.S. federal income taxes, which may reduce the cash available for distribution to us and, in turn, to our unitholders. If the IRS or other state or local jurisdictions were to successfully assert that this corporation has more tax liability than we anticipate or legislation was enacted that increased the corporate tax rate, the cash available for distribution could be further reduced. The income tax return filings positions taken by this corporate subsidiary require significant judgment, use of estimates, and the interpretation and application of complex tax laws. Significant judgment is also required in assessing the timing and amounts of deductible and taxable items. Despite our belief that the income tax return positions taken by this subsidiary are fully supportable, certain positions may be successfully challenged by the IRS, state or local jurisdictions.

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 recapture. In addition, because the amount realized includes a unitholder's share of our nonrecourse liabilities, if you

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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. Our counsel is unable to opine as to the validity of such filing positions. 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 for federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We prorate our items of income, gain, loss and deduction for federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations and, although the U.S. Treasury Department issued proposed Treasury Regulations allowing a similar monthly simplifying convention, such regulations are not final and do not specifically authorize the use of the proration method we have adopted. Accordingly, our counsel is unable to opine as to the validity of this method. If the IRS were to challenge this method or new Treasury Regulations were issued, we may 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 effect a short sale of common units may be considered as having disposed of those common units. If so, he would no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.

Because a unitholder whose common units are loaned to a "short seller" to effect a short sale of common units may be considered as having disposed of the loaned common units, he may no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deductions with respect to those common units may not be reportable by the unitholder, and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Our counsel has not

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rendered an opinion regarding the treatment of a unitholder where common units are loaned to a short seller to effect a short sale of common units; therefore, 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.

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.

We will be considered to have technically terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. Our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1 if relief was not available, as described below) for one fiscal year and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred. The IRS has announced a publicly traded partnership technical termination relief program whereby, if a publicly traded partnership that technically terminated requests publicly traded partnership technical termination relief and such relief is granted by the IRS, among other things, the partnership will only have to provide one Schedule K-1 to unitholders for the year in which the termination occurs, notwithstanding two partnership tax years.

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

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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. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in our common units.

ITEM 1B.         UNRESOLVED STAFF COMMENTS

None.

ITEM 2.            PROPERTIES

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

•

Mineral Reserves;



•

Mines and Wet Plants;



•

Dry Plant Facilities;



•

Transportation Logistics and Infrastructure;



•

Dallas-Fort Worth Facility; and



•

Birmingham Facility.

In addition to these segment properties, we lease 3,415 square feet of Class C office space for our corporate headquarters in Southlake, Texas. This lease expires in 2015.

ITEM 3.            LEGAL PROCEEDINGS

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

Environmental Matter

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

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ITEM 4.            MINE SAFETY DISCLOSURES

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

All of our production facilities are classified as mines and are subject to regulation by MSHA under the Federal Mine Safety and Health Act of 1977 (the "Mine Act"). MSHA inspects our mines on a regular basis and issues various citations and orders when it believes a violation has occurred under the Mine Act. Following passage of The Mine Improvement and New Emergency Response Act of 2006, MSHA significantly increased the numbers of citations and orders charged against mining operations. The dollar penalties assessed for citations issued has also increased in recent years. Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.104) is included in Exhibit 95.1 to this Annual Report on Form 10-K.

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PART II

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

Our common units are listed on the NYSE under the symbol "EMES" and began trading on May 14, 2013 on a "when-issued" basis. Prior to May 14, 2013, our common units were not listed on any exchange or traded in any public market. On March 17, 2014, the closing market price for the common units was $55.43 per unit. As of March 17, 2014, there were 23,628,208 common units outstanding. There were approximately 10,627 record holders of common units on December 31, 2013. 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 since our initial public offering:

Cash Distribution Policy

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

There is no guarantee that we will distribute quarterly cash distributions to our unitholders. Our cash distribution policy is subject to restrictions on cash distributions under our credit facility. Specifically, our credit facility contains financial tests and covenants that we must satisfy before quarterly cash distributions can be paid. In addition, our ability to pay quarterly cash distributions will be restricted if an event of default has occurred under our credit facility. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operation — Liquidity and Capital Resources — Credit Facility.

Issuer Purchases of Equity Securities

None.

Performance Graph

The following graph compares the performance of our common units since the IPO to the Standard & Poor's 500 Index (the "S&P 500 Index") and the Alerian MLP Total Return Index (the "Alerian MLP Index") by assuming $100 was invested in each investment option as of May 14, 2013, the date of the IPO,

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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.

ITEM 6.            SELECTED FINANCIAL DATA

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

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

•

Our IPO in May 2013 resulted in:



•

net proceeds of $116.2 million;



•

non-recurring charges of $11.0 million;



•

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



•

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



•

The financial position and results of operations of Direct Fuels were included in the consolidated financial statements from and as of the date of acquisition, May 14, 2013. Our acquisition of Direct Fuels expanded our Fuel segment's operations, gained new customers, improved our earnings, and increased our markets through a larger geographical presence.

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•

During 2011 and 2012, our Sand segment incurred significant growth capital expenditures to keep pace with rapidly increasing demand for our Northern White frac sand.

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Quarterly Data

ADJUSTED EBITDA

Adjusted EBITDA is a non-GAAP financial measure we define generally as: net income plus interest expense, tax expense, depreciation, depletion and amortization expense, non-cash charges and unusual or non-recurring charges less interest income, tax benefits and selected gains that are unusual or non-recurring. Adjusted EBITDA is used as a supplemental financial measure by our management and external users of our financial statements, such as investors and commercial banks, to assess:

•

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



•

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

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•

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



•

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

We believe that Adjusted EBITDA provides useful information to investors because, when viewed with our GAAP results and the accompanying reconciliations, it provides a more complete understanding of our performance than GAAP results alone. We also believe that external users of our financial statements benefit from having access to the same financial measures that management uses in evaluating the results of our business. In addition, the lenders under our credit facility use a metric similar to Adjusted EBITDA to measure our compliance with certain financial covenants.

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

Reconciliation of Net Income (Loss) to Adjusted EBITDA

The following tables present a reconciliation of net income (loss) to Adjusted EBITDA for each segment, corporate, and in total.

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

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

Acquisition

On May 14, 2013, we completed the acquisition of Direct Fuels' net assets for $98.3 million. Direct Fuels operates a motor fuel terminal and transmix processing facility in Texas. The acquisition of Direct Fuels expands our geographic presence into the Dallas-Fort Worth, Texas market. Direct Fuels is part of our Fuel segment.

How We Evaluate Our Operations

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

Sales volumes

We view the total volume of frac sand and refined products that we sell as an important measure of our ability to effectively utilize our assets. Higher volumes improve profitability through the spreading of fixed costs over greater volumes. Our sales volumes are subject to seasonality, particularly in our Sand segment. Please see Part I, Item 1. Business.

Adjusted EBITDA

Adjusted EBITDA, a non-GAAP financial measure, is used as supplemental measures by our management and by external users of our financial statements such as investors, commercial banks, research analysts and others, to assess:

•

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



•

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



•

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

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

Recent Trends

Sand Segment

Over the last few years there has been a significant overall increase in both horizontal drilling activity and related hydraulic fracturing services, which has resulted in a corresponding increase in demand for frac sand and other proppants. Horizontal drilling rigs have increased from 447 at January 4, 2008 to 1,146 at December 27, 2013, according to the North American rig count data published by Baker Hughes Inc. on March 21, 2014 (the "Baker Hughes Report").

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In addition to the overall increase in the number of horizontal drilling rigs, over the last six years there has been a significant shift in drilling activity in the United States from dry gas formations to oil-and liquids-rich natural gas formations, which has led to a corresponding increase in demand for coarser frac sands that facilitate the conductivity of oil- and liquids-rich natural gas drilling applications. According to the Baker Hughes Report, at January 4, 2008 there were fewer than 400 rigs drilling for oil - and liquids-rich natural gas and over 1,400 rigs drilling for dry natural gas. At December 31, 2013, there were over 1,300 drilling rigs for oil- and liquids-rich natural gas in North America, while the dry natural gas rig count had declined to less than 400. We anticipate that the increased growth in demand for frac sand in 2011, 2012 and 2013 arising from increased hydraulic fracturing activities, particularly in oil and liquids-rich natural gas drilling applications will continue for the foreseeable future. As a result, we expect to continue to experience increased demand for our Northern White frac sand.

While the increased demand for frac sand has resulted in favorable pricing trends over the past several years for frac sand producers, we experienced a small decline in overall pricing in 2013 due to increased market supply. However, the shift of drilling activity from dry gas formations to oil and liquids-rich natural gas formations has led to a corresponding increase in demand for coarser frac sands and, as a result, the prices for coarser frac sands have remained strong. The U.S. Bureau of Labor Statistics Producer Price Index for Industrial Sand Mining—Hydraulic fracturing sand, indicates that prices declined 9.7% during the twelve month period ended December 31, 2013. We believe that the continued shift from dry gas to liquids-rich plays will allow our prices to remain relatively consistent in the future.

Fuel Segment

Total consumption of liquid fuels in the United States, including both fossil fuels and biofuels, is expected to remain relatively stable from 18.5 million barrels per day in 2012 to 18.7 million barrels per day in 2040, according to the Annual Energy Outlook 2014 Early Release Overview published by the Energy Information Administration in December 2013. The transportation sector is expected to continue to account for the largest percentage of demand for liquid fuels (as measured by energy content) through 2040.

We believe that transmix processing volumes generally increase or decrease at approximately the same rate as the consumption of liquid fuels in the United States. Transmix processing volumes are also driven by changes in governmental regulations. We believe the only pending regulatory changes that will impact the volume of transmix produced in the United States are the regulations promulgated by the EPA in mid-2006 that required a reduction in the sulfur content of diesel fuel. Under these regulations, which resulted in significant increases in transmix volumes following their promulgation in 2006, the maximum allowable sulfur content for on-road diesel fuel was reduced on a phased basis from 500 ppm (low sulfur diesel) to 15 ppm (ultra-low sulfur diesel). In order to prevent contamination of the lower-sulfur fuels traveling through pipelines, pipeline operators had to reconfigure the way fuel was transported, which resulted in more interfaces between products and deeper "cuts" in those interfaces. Under the EPA's regulations, all on-road and off-road diesel had to meet a 15 ppm sulfur standard as of June 2010. A settlement agreement with the EPA indicates that the agency will allow use of 500 ppm diesel produced by transmix processors in locomotive engines as long as there is a market for it; however, railroads must begin purchasing Tier 4 locomotives, which only accept 15 ppm sulfur diesel, starting in 2015. As a result, 500 ppm sulfur diesel will be phased out of the locomotive market over a several year period beginning in 2015. However, the settlement agreement allows us and other transmix process to sell 500 ppm diesel produced to certain marine markets with no phase-out date.

2014 Outlook

We expect many of the recent trends in our Sand segment to continue into 2014, including stronger prices and increased demand for frac sand, especially the coarse Northern White frac sand that we sell. Further, we believe that our growing logistics network and capabilities are going to help us differentiate ourselves

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from those that lack critical infrastructure, and that the industry will see consolidation. We believe that our Fuel segment will contribute incrementally to 2014 results. While our 2014 Fuel segment expectation is generally positive, we do not believe that 2014 will repeat the exceptional earnings growth reported in 2013. We expect Fuel segment results to return to more historic levels.

Results of Operations

The following table summarizes our consolidated operating results for 2013, 2012 and 2011.

Consolidated Summary

Our company has experienced significant change over the past three years, growing from a net loss of $0.7 million in 2011 to a net profit of $35.2 million in 2013. Most notable are the following events:

•

substantial growth of our Sand segment through addition of the New Auburn plant in 2011 and the Barron plant in 2012, which increased our overall profitability significantly;



•

the acquisition of Direct Fuels to substantially increase our Fuels segment in 2013; and



•

our IPO in 2013, which brought these two segments together for the first time and allowed us to refinance our debt at more favorable terms going forward.

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Sand Segment

Overview

The operating income for our sand segment has seen substantial growth from a loss of $1.8 million in 2011 to an operating profit of $27.4 million in 2012 and $55.3 million in 2013. Management has focused on growing this segment of our business by adding the New Auburn plant in late 2011 and the Barron plant in late 2012, as well as developing our distribution and logistics services to better serve our customers through additional transload sites in 2013. At year-end 2013, we had twelve transload sites in the U.S. and Canada. Many of these sites are considerably distant from our processing facilities in Wisconsin. Due to the distance to these markets, we charge higher prices to recover freight and handling. This condition increases our revenues and margin, but the margin percentage at our transload sites is lower than for sand sold directly from our Wisconsin plants due to lower markups on the incremental transportation costs.

We currently are constructing two more wet plants in Barron, WI and Arcadia, WI that we expect to be operational in 2014.

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012

Revenues

Sand revenues increased by $101.1 million, or 152%, from 2012 to 2013. This increase is attributable primarily to a 117% increase in total volumes sold with the addition of our Barron facility in December 2012 and volume increases from the New Auburn facility, which began operating in October 2011. We also expanded our logistics and distribution network with the addition of transload facilities in the U.S. and Canada to serve our customers in various shale plays and basins. We generally charge higher prices at our transload sites in order to cover the additional costs for transportation from our plants to the transload sites. Management continues to focus on initiatives to strengthen and improve logistics service, including increased storage capacity and access to remote transload sites. These logistics-based initiatives are intended to complement and enhance customer support.

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The major changes from 2012 to 2013 are as follows:

•

$97.0 million increase for the Barron plant due to:



•

a full year of production after its December 2012 opening;



•

an estimated $34 million for higher markups related to sales from transload sites; and



•

per unit prices increased due mainly to the higher prices charged at transload facilities, which are generally closer to our customers' drilling locations than our plant.



•

$5.5 million increase for the New Auburn plant due to:



•

a production capacity increase with installation of an additional screen deck in 2013;



•

partially offset by select customer discounts.



•

$1.4 million decrease for the Kosse plant due primarily to decreased volumes as drilling activity shifted away from the nearby shale plays.

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

Our cost of goods sold consists primarily of direct costs such as purchased sand, transportation to the plant or to transload facilities, mining and processing costs, and plant wages as well as indirect costs such as plant repairs and maintenance. All major components of our direct costs increased with our increased production and with the operations of our new plants, particularly transportation costs as we expanded our distribution network with new transload sites. The plant maintenance and repairs did not increase significantly, as the Wisconsin plants are still quite new. The most significant components of the $64.0 million increase from 2012 to 2013 are:

•

$28.9 million increase in cost of purchased sand, due to purchasing sand for the new Wisconsin plants;



•

$28.6 million increase in cost of transportation of sand, mainly for additional railcars to transport sand from our plants to the transload sites; and



•

$3.6 million increase in mining costs related to the new Arland mine.

Depreciation, depletion and amortization

The $4.1 million increase in depreciation, depletion and amortization is due primarily to a full year of depreciation for the Barron facility that was placed in service at the end of 2012. The major changes from 2012 to 2013 are:

•

$3.2 million increase for the Barron facility;



•

$0.5 million increase for SSS corporate office, which was established in 2012; and



•

$0.4 million increase for the New Auburn facility.

Selling, general and administrative expense

Increased selling, general and administrative expense is attributable primarily to the addition of new sales and administrative employees as well as additional insurance coverage for our expanded operations.

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Year Ended December 31, 2012 Compared to Year Ended December 31, 2011

Revenues

Revenues increased by $38.5 million, or 137%, primarily due to opening our New Auburn plant in October 2011, which accounted for 87% of our total frac sand sales volume during 2012. The major changes from 2011 to 2012 are as follows:

•

$51.8 million increase in sales from our New Auburn plant due to a full year of operations in 2012; and



•

$13.9 million decrease in sales for our Kosse plant as management decided to focus our efforts on sales from our Wisconsin plants (which produce higher marginal revenues).

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

Cost of goods sold, as a percent of revenue, decreased from 71% in 2011 to 41% in 2012, due primarily to:

•

$21.6 million increase in costs for New Auburn, due mainly to increased volumes;



•

$12.8 million decrease in costs at Kosse, due to a decrease of sales of Wisconsin sand for our Kosse facility; and



•

startup costs of our new Barron facility.

Depreciation, depletion and amortization

The $4.1 million increase in depreciation, depletion and amortization is due primarily to a full year of depreciation for the New Auburn facility.

Impairment of assets

In 2011, our management decided to sell a parcel of land which was not used in our core operations. We recorded a non-recurring loss of $0.8 million at that time to adjust the carrying value down to its expected net proceeds. The asset was sold in 2012 for the expected amount.

Fuel Segment

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Overview

The operating income for our Fuel segment declined slightly from $2.6 million in 2011 to $2.0 million in 2012, with considerable growth to $12.6 million in 2013. The 2012 decline resulted principally from litigation costs related to an environmental claim. The 2013 increase is attributable primarily to the purchase of Direct Fuels in May 2013, combined with improved fuel margins. The purchase of Direct Fuels was part of management's strategy to expand the segment's geographical range and incorporate a leader in transmix refining.

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012

Revenues

The $148.1 million, or 27%, increase in Fuel segment revenues is attributable to a 27% increase in total volumes sold. The increase in volume relates directly to incremental sales derived from Direct Fuels after the purchase on May 14, 201.3, partially offset by reduced gasoline sales in the Birmingham, Alabama market. The Birmingham market experienced constrained gasoline supplies for much of 2013 due to pipeline allocations. Major changes from 2012 to 2013 are as follows:

•

$218.2 million for Direct Fuels' incremental revenues (May 14, 2013 through December 31, 2013);



•

$25.8 million increased sales of diesel fuel; and



•

$5.8 million increase in excise and similar taxes; offset by



•

$101.0 million reduced revenues due to constrained gasoline supplies in the Birmingham market..

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

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

Our cost of goods sold consists primarily of direct costs associated with the purchase of refined fuels, transmix feedstock, plant labor and burden, and costs to operate our transmix and terminal facilities. Our cost of goods sold increased 23% in 2013 as compared to 2012. This net increase results from incremental costs associated with Direct Fuels partially offset by reduced purchases of gasoline and a higher percentage of refined fuels derived from transmix refining. The major components of the $128.5 million increase from 2012 to 2013 are as follows:

•

$209.1 million of Direct Fuels' incremental cost of goods sold (May 14, 2013 through December 31, 2013);



•

$23.9 million increase in diesel fuel costs;



•

$5.8 million increase in excise and similar taxes; and



•

$1.3 million increase in costs associated with plant operations; offset by



•

$109.6 million decrease for reduced gasoline purchases due to constrained supplies in the Birmingham market.

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

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Depreciation, depletion and amortization

The $7.6 million increase in depreciation, depletion and amortization is due to the incremental costs associated with our purchase of Direct Fuels on May 14, 2013, specifically:

•

$6.8 million in amortization of intangible assets; and



•

$0.8 million of depreciation.

Selling, general and administrative expense

Our selling, general and administrative expenses increased $1.4 million, or 30%. The prime driver to this increase is the purchase of Direct Fuels on May 14, 2013.

Year Ended December 31, 2012 Compared to Year Ended December 31, 2011

Revenues

The $208.1 million, or 60%, increase in Fuel segment revenues is attributable primarily to a 59% increase in total volumes sold. The volume increase relates directly to expanded gasoline sales to an existing customer combined with net increases to other accounts. Major changes from 2011 to 2012 are as follows:

•

$190.3 million for volume increases; and



•

$18.2 million increase in excise and similar taxes.

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

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

Our cost of goods sold consists primarily of direct costs associated with the purchase of refined fuels, transmix feedstock, plant labor and burden, and costs to operate our transmix and terminal facilities. The overall 61% increase in cost of goods sold was caused by increased volumes and higher product costs, combined with costs associated with plant operations. Major changes from 2011 to 2012 are as follows:

•

$183.2 million for increased volumes;



•

$18.2 million increase in excise and similar taxes;



•

$6.0 million increase in product costs; and



•

$0.6 million increase in plant operating costs.

Selling, general and administrative expense

Our selling, general and administrative expenses increased $0.8 million, or 20%. Major changes from 2011 to 2012 are as follows:

•

increase in litigation expense: $0.7; and



•

increase in business licenses: $0.3; offset by



•

reduced compensation expense: $0.3.

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Corporate

Overview

All of our IPO transaction-related costs, equity-based compensation and other overhead items not allocated to our two segments are included in corporate. As the Sand and Fuel segments were operated separately without consolidated EMES management oversight prior to our IPO in May 2013, and other costs such as equity-based compensation and costs of being a publicly traded limited partnership began at that same time, corporate expenses increased significantly in 2013 compared to any prior year.

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012

Selling, general and administrative expenses

Most of the $10.1 million increase in corporate selling, general and administrative expenses is attributable to the $5.7 million of equity-based compensation recorded subsequent to our IPO. See Note 11 to our Consolidated Financial Statements for further discussion of equity-based compensation. The remaining increase is primarily for professional fees, salaries and other related costs necessary to manage our newly combined business and provide the incremental services necessary for a publicly traded partnership (such as compliance with SEC, Sarbanes-Oxley, and NYSE requirements, additional insurance coverage and director fees).

IPO transaction-related costs

We incurred generally non-recurring expenses related directly to the IPO. These costs consist primarily of incentive compensation and payroll-related costs paid to management. In addition, we incurred indirect legal, accounting, and other professional fees associated with the IPO transaction not related to the issuance of equity and debt. See Note 12 to our Consolidated Financial Statements for further details.

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Interest expense, net

In the last half of 2012, we had added a substantial amount of long-term debt, which was incurring interest expense until we refinanced substantially all of our debt with the proceeds from our IPO on May 2013. Beginning in May 2013, we have lower overall levels of debt with more favorable terms, which we expect to continue during the term of our current credit agreement. The combination of these events resulted in a relatively flat net expense from 2012 to 2013. See Note 8 to our Consolidated Financial Statements for a discussion of long-term debt.

Loss (gain) on extinguishment of debt

At the time of our IPO in May 2013, all of our existing debt was retired, for a net $0.9 million loss on extinguishment of debt. In 2012, SSS refinanced a portion of its previous debt and recorded $0.4 million in loss on extinguishment of debt related to the proportional amount of deferred financing costs on the retired debt. See Note 8 to our Consolidated Financial Statements for a discussion of long-term debt.

Other

The net change from 2012 to 2013 is due to a non-recurring litigation settlement expense of $0.8 million in 2012 and a $0.2 million gain in fair value of interest rate swaps in 2013.

Year Ended December 31, 2012 Compared to Year Ended December 31, 2011

Interest expense, net

Interest expense increased significantly from 2011 to 2012 due to the net addition of over $46 million of debt in 2012. See Note 8 to our Consolidated Financial Statements for a discussion of long-term debt.

Loss (gain) on extinguishment of debt

On April 1, 2011, AEC restructured its debt under a troubled debt restructuring, resulting in a $0.5 million gain on debt restructuring. In 2012, SSS refinanced a portion of its previous debt and recorded $0.4 million in loss on extinguishment of debt related to the proportional amount of deferred financing costs on the retired debt. See Note 8 to our Consolidated Financial Statements for a discussion of long-term debt.

Gain on extinguishment of trade payable

In 2011, AEC entered into an agreement with a third-party product supplier to settle a trade payable for an amount less than its carrying amount. AEC paid the product supplier $1.6 million in cash and transferred real estate with a book value and fair value of $0.1 million for full settlement of the $2.9 million trade payable, which resulted in a $1.2 million gain on extinguishment of trade payable.

Other

The net change from 2011 to 2012 is due to a $0.2 million gain in fair value of our interest rate swaps in 2011 and a $0.8 million non-recurring litigation settlement expense in 2012.

Liquidity and Capital Resources

Our principal liquidity requirements are to finance current operations, fund capital expenditures, including acquisitions from time to time, to service our debt and to pay distributions to partners. Our sources of liquidity generally include cash generated by our operations, borrowings under our revolving line of credit and issuances of equity and debt securities. We believe that cash generated from these sources will be sufficient to meet our short-term working capital requirements and long-term capital expenditure requirements for at least the next twelve months.

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Equity Offering (IPO)

On May 8, 2013, the Partnership priced its initial public offering of 7,500,000 common units at a price to the public of $17.00 per unit ($15.85 per common unit, net of underwriting discounts and structuring fee). On May 20, 2013, the underwriters exercised their option to purchase an additional 209,906 common units. The net proceeds from the IPO of $122.2 million (including over commitment allocation of $3.3 million), after deducting the underwriting discount and the structuring fee, were used to: (i) repay existing subsidiary debt, in the amount of $87.6 million, (ii) pay offering expenses of $10.6 million, (iii) pay cash-based compensation awards to senior management of $8.9 million, (iv) provide the Partnership with working capital of $11.5 million and (v) provide a distribution to equity holders of $3.6 million.

Credit Agreement

On May 14, 2013, we entered into a revolving credit and security agreement (the "Credit Agreement") among the Emerge Energy Services LP, as parent guarantor, each of its subsidiaries, as borrowers (the "Borrowers"), and PNC Bank, National Association, as administrative agent and collateral agent. We subsequently amended the Credit Agreement to revise certain definitions and to increase the commitment amount. The Credit Agreement, as amended, provides for a $200 million variable rate senior secured revolving credit facility (the "new credit facility") which is available to repay our existing indebtedness on the closing date of the IPO, to fund fees and expenses incurred in connection with the IPO and the credit facility, and for general business purposes, including working capital requirements, capital expenditures, permitted acquisitions, making debt payments (but not prepayments) when due, and making distributions and dividends. In addition, the Credit Agreement includes a sublimit of up to $15 million for the issuance of letters of credit. Substantially all of the assets of the Borrowers are pledged as collateral under the Credit Agreement. The new credit facility matures on May 14, 2018.

Loans under the new credit facility bear interest at our option at either:

•

a Base Rate (as defined in the Credit Agreement), which will be the base commercial lending rate of PNC Bank, as publicly announced to be in effect from time to time, plus an applicable margin ranging from 1.75% to 2.50% based on our total leverage ratio; or



•

LIBOR plus an applicable margin ranging from 2.75% to 3.50% based on our total leverage ratio.

We initially borrowed $112.6 million to (i) make distributions of $17.0 million to Superior Silica Holdings LLC ("SSH") and to fund the cash payment in the Direct Fuels acquisition amounting to $22.2 million; and, (ii) repay $73.5 million of existing SSH debt. As part of the original Credit Agreement, we incurred $3.6 million of direct financing costs for professional and legal fees, which we recorded as deferred financing cost. We subsequently incurred $0.2 in bank fees related to amendments that were also recorded as deferred financing cost.

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

•

a fixed charge coverage ratio (as defined in the Credit Agreement) of not less than 1.10 to 1.00; and



•

total leverage ratio (as defined in the Credit Agreement) of not greater than 3.00 to 1.00. The requirement to maintain the total leverage ratio is subject an increase to 3.50 to 1.00 in connection with certain permitted acquisitions.

At December 31, 2013, we were in compliance with our loan covenants and had undrawn availability under this credit facility totaling $90.3 million. At December 31, 2013, our outstanding borrowings under the Credit Agreement bore interest at a weighted-average rate of 2.94%.

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Cash Flow Summary

The table below summarizes our cash flows for the years ended December 31, 2013, 2012 and 2011.

Operating Cash Flows

Net cash provided from operating activities has generally trended the same as our net income adjusted for non-cash transactions, which aggregated to $67.5 million, $28.2 million and $6.2 million for 2013, 2012 and 2011, respectively. These were offset by changes in our working capital, which decreased during times of lower profitability in 2011 and 2012, but has improved significantly subsequent to our IPO in May 2013.

Investing Cash Flows

Capital expenditures for the Barron and New Auburn dry plants required significant cash outlays in 2012 and 2011. We expended lesser amounts in 2013 for a new wet plant in Arland, WI and a capacity expansion at the New Auburn dry plant. The 2013 decrease in capital expenditures was offset by a $16.7 million net cash purchase of Direct Fuels in May 2013. We expect to pay $8.3 million in 2014 to complete construction begun in late 2013 on a new wet plant in Wisconsin.

Financing Cash Flows

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

The most significant differences in our financing cash flows came about as a result of our May 2013 IPO. Not only did we receive $116.6 million in net proceeds (after exercise of the overallotment and payment of offering costs), but we were able to reduce our overall debt amounts and will now be making distributions to our unitholders on a quarterly basis. In addition, we had significant non-recurring transactions that created volatility between years, including a $16.0 million advance from our customers in 2011 and a one-time distribution to Direct Fuels' prior owners in relation to our purchase of Direct Fuels in May 2013.

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Management Incentive Plans

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

Contingencies

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

Contractual Obligations

We have long-term contractual obligations that are required to be settled in cash. The amounts of our minimum contractual obligations as of December 31, 2013 were as follows:

Off-Balance Sheet Arrangements

As of December 31, 2013, our Sand segment had an outstanding letter of credit to the favor of Barron County for $258,000. We provided this letter of credit to assure performance under the reclamation plan filed with Barron County. We do not believe the letter of credit could have an effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that would be material to investors. We expect this letter of credit will be retired once we have posted the required bond with the appropriate governmental unit. On October 25, 2013, our Fuel segment issued a $3.7 million letter of credit to a transmix supplier and pipeline common carrier. This letter of credit supports our transmix purchases and pipeline fuel shipments and expires on April 30, 2014.

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions. These estimates and assumptions affect the amounts reported in our Consolidated Financial Statements and notes. We base our estimates on historical experience and various other

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

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

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

•

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



•

changes in technology that render an asset obsolete;



•

changes in expected salvage values; or



•

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

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

Asset Retirement Obligations

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

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

The liability is accreted over time through periodic charges to earnings. In addition, the asset retirement cost is capitalized as part of the asset's carrying value and amortized over the life of the related asset. Reclamation costs are periodically adjusted to reflect changes in the estimated present value resulting from the passage of time and revisions to the estimates of either the timing or amount of the reclamation and

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abandonment costs. The reclamation obligation is based on when spending for an existing environmental disturbance is expected to occur. If the asset retirement obligation is settled for other than the carrying amount of the liability, a gain or loss will be recognized on settlement. We review, on an annual basis, unless otherwise deemed necessary, the reclamation obligation at each mine site in accordance with ASC guidance for accounting reclamation obligations.

Impairment of Goodwill

In accordance with FASB ASC 350, Intangibles – Goodwill and Other, goodwill is tested no less than annually unless indicators of impairment exist in interim periods. The impairment test uses a two-step process, which is performed at the reporting unit level. Step one compares the fair value of the reporting unit to its carrying value. We calculate the fair value using the enterprise value-market capitalization approach. This approach uses estimates and assumptions that are believed to be reasonable at the time of the calculation. If the carrying value exceeds the fair value, there is a potential impairment and step two must be performed. Step two compares the carrying value of the reporting unit's goodwill to the implied fair value (i.e., the fair value of the reporting unit less the fair value of the unit's assets and liabilities, including identifiable intangible assets). If the carrying value of goodwill exceeds its implied fair value, we record the excess as an impairment charge to earnings. We performed our annual assessment of goodwill in the fourth quarter of 2013, and determined during Step one that the fair value of the reporting unit (our Fuel segment) exceeds its carrying value. Therefore, it was not necessary to perform Step two of the analysis.

Impairment of Long-Lived Assets

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

Equity-Based Compensation

We account for equity-based compensation by recognizing an expense in the financial statements based on the fair value method. The fair value method requires that a fair value be assigned to a unit grant on its grant date and that this value be amortized over the grantees' required service period. Restricted and phantom units have a fair value equal to the fair market value of the common units on the date of the grant. We amortize the fair value of the restricted and phantom units over the vesting period using the straight-line method. The fair value of a certain equity award to a key employee was determined using a Monte Carlo simulation. For performance-based awards, we make estimates as to the probability of the underlying performance being achieved and record expense if the performance will probably be achieved.

Accounting for Contingencies

Our financial results may be affected by judgments and estimates related to loss contingencies. Litigation contingencies may require significant judgment in estimating amounts to accrue. We accrue liabilities for litigation contingencies when such liabilities are considered probable of occurring and the amount is reasonably estimable.

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ITEM 7A.        QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Commodity Price Risks

We are exposed to market risk with respect to the pricing that we receive for our sand production. Realized pricing for sand from our New Auburn facility is primarily driven by take-or-pay supply agreements with two large well-capitalized oilfield services companies, whereas realized pricing at the Barron County dry plant facility is driven by a combination of take-or-pay contracts, fixed volume, and efforts-based agreements in addition to sales on the spot market. The terms of the two New Auburn take-or-pay contracts expire in 2014 and 2021, but either we or our customer can terminate the agreement expiring in 2021 upon 120 days' written notice at any time after the expiration of the period during which the customer is entitled to receive discounts on its purchase price per ton of frac sand in connection with its prior advance payments to us, which will not occur until October 2014 or later. Prices under all of our supply agreements are generally fixed and are subject to adjustment, within limitations, in response to certain cost increases. As a result, our realized prices for frac sand may not grow at rates consistent with broader industry pricing. During periods of rapid price growth, our realized prices may grow more slowly than those of competitors, and during periods of price decline, our realized prices may outperform industry averages. We do not enter into commodity price hedging agreements with respect to sand production.

We are also exposed to market risk with respect to the prices we charge for refined fuels products and that we pay for transmix, wholesale fuel and other feedstocks. Realized margins for our refined fuel products are determined by the relationship between the prices charged for fuel and the prices paid for transmix, wholesale fuel and other feedstocks. We purchase transmix, wholesale fuel and other feedstocks based on several different regional price indices, the most important of which are the Platt's Gulf Coast gasoline and diesel price postings. The costs of these purchases are generally set on the day of purchase. We typically sell fuel products within seven to ten days of supply purchases at then prevailing market prices. If the market price for our fuel products declines during this period or generally does not increase commensurate with any increases in supply and processing costs, our margins will fall and the amount of cash available for distribution will decrease. In addition, because we value our inventory at the lower of cost or market value, if the market value of our inventory were to decline to an amount less than our cost, we would record a write-down of inventory and a non-cash charge to cost of sales. In a period of declining prices for transmix or refined products, our inventory valuation methodology may result in decreases in reported net income.

We utilize financial hedging arrangements (mainly futures traded on the New York Mercantile Exchange) to hedge a portion of our gasoline and diesel inventory, which reduces commodity price exposure on some of these activities. We record these commodity derivatives at fair value on the consolidated balance sheet with resulting gains and losses reflected in cost of fuel as reported in the consolidated statements of operations. We derive fair values principally from published market quotes. The precise level of open position derivatives is dependent on inventory levels, expected inventory purchase patterns and market price trends.

A hypothetical increase or decrease in commodity prices by 1.0% would have changed our cost of goods sold by $7.4 million for the year ended December 31, 2013, with some offsets in increased sales prices.

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Interest Rate Risk

We are exposed to fluctuations in interest rates charged on our variable rate debt. We enter into certain interest rate swap agreements in accordance with our risk management strategy. As of December 31, 2012 and 2011, we were not a party to any interest rate swap agreements. During 2013, we entered into interest rate swap agreements that will effectively convert $70 million notional amount of our variable rate debt to a fixed rate, effective October 14, 2014. We account for the interest rate swap agreements on a mark-to-market basis through current earnings even though they were not acquired for trading purposes. We recognized gains related to changes in fair values for interest rate swap agreements of $0.2 million, $0 and $0.2 million for the years ended December 31, 2013, 2012 and 2011, respectively.

A hypothetical increase or decrease in interest rates by 1.0% would have changed our interest expense by $1.2 million for the year ended December 31, 2013.

Customer Credit Risk

We are subject to risks of loss resulting from nonpayment or nonperformance by our customers. We examine the creditworthiness of third-party customers to whom we extend credit and manage exposure to credit risk through credit analysis, credit approval, credit limits and monitoring procedures. Our top three customer balances accounted for 31% and 37% of our net accounts receivable at December 2013 and 2012, respectively.

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ITEM 8.            FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

EMERGE ENERGY SERVICES LP
INDEX TO FINANCIAL STATEMENTS

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We have audited the accompanying consolidated balance sheets of Emerge Energy Services LP (the "Partnership") as of December 31, 2013 and 2012 and the related consolidated statements of operations, partners' equity, and cash flows for each of the three years in the period ended December 31, 2013. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Emerge Energy Services LP at December 31, 2013 and 2012, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2013, in conformity with accounting principles generally accepted in the United States of America.

/s/ BDO USA, LLP

Dallas, Texas

March 24, 2014

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EMERGE ENERGY SERVICES LP
CONSOLIDATED BALANCE SHEETS
($ in thousands)

See accompanying notes to consolidated financial statements.

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EMERGE ENERGY SERVICES LP
CONSOLIDATED STATEMENTS OF OPERATIONS
($ in thousands except per unit data)

See accompanying notes to consolidated financial statements.

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EMERGE ENERGY SERVICES LP
CONSOLIDATED STATEMENTS OF PARTNERS' EQUITY
($ in thousands)

See accompanying notes to consolidated financial statements.

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EMERGE ENERGY SERVICES LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
($ in thousands)

See Note 18 for supplemental disclosures.

See accompanying notes to consolidated financial statements.

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EMERGE ENERGY SERVICES LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.     ORGANIZATION AND BASIS OF PRESENTATION

Organization

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

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

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

We are a growth-oriented energy services company engaged in: (i) the business of mining, producing, and distributing silica sand that is a key input for the hydraulic fracturing of oil and gas wells; and, (ii) the business of distributing refined motor fuels, refining transportation mixture ("transmix") and biodiesel, operating bulk motor fuel storage terminals, and providing complementary services. We report silica sand activities through the Sand segment and motor fuel operations through the Fuel segment. We report items of income (if any) and expense that cannot be directly associated with the Sand and Fuel segments as "corporate."

The Sand segment conducts mining and processing operations from facilities located in Wisconsin and Texas. In addition to mining and processing silica sand for the oil and gas industry, the Sand segment sells its product for use in building products and foundry operations. The Fuel segment operates transmix processing facilities located in the Dallas-Fort Worth area with a second transmix unit in Birmingham, Alabama. The Fuel segment also offers third-party bulk motor fuel storage and terminal services, bio-diesel refining, the sale and distribution of wholesale motor fuels, reclamation services (which consists primarily of cleaning bulk storage tanks used by other petroleum terminal and others), and the blending of renewable fuels.

Initial Public Offering of Emerge Energy Services LP

On May 8, 2013, the Partnership priced an initial public offering of 7,500,000 limited partner common units ("common units") at a price of $17.00 per common unit ($15.85 per common unit, net of underwriting discounts and structuring fee). The IPO was made pursuant to a registration statement on Form S-1 originally filed on March 22, 2013, as amended (Registration No. 333-187487) that was declared effective by the Securities and Exchange Commission ("SEC") on May 8, 2013. On May 20, 2013, the underwriters

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exercised their option to purchase an additional 209,906 common units. The net proceeds from the IPO of $122.2 million (including net proceeds of $3.3 million from the exercise of the underwriters' over-allotment option), after deducting the underwriting discount and the structuring fee, were used to: (i) repay existing subsidiary debt, in the amount of $87.6 million, (ii) pay offering expenses of $10.6 million, (iii) pay and initial funding of cash-based compensation awards to senior management of $8.9 million, (iv) provide the Partnership with working capital of $11.5 million, (v) provide a distribution to pre-IPO equity holders of $3.3 million ($2.6 million to predecessors' owners and $0.7 million to Direct Fuels' owners as part of the original purchase price), and (vi) pay certain prepaid items of $0.3 million.

Upon the closing of the IPO, the consolidated historical financial statements of Superior Silica Holdings LLC ("SSH"), AEC Holdings LLC ("AEC Holdings"), and the Partnership became the historical financial statements as discussed below.

Basis of Presentation and Consolidation

Prior to completion of our IPO, SSH and AEC Holdings, which together constitute our Predecessor for accounting purposes, were under the common control of a private equity fund managed and controlled by Insight Equity. As a result, their contribution to the Partnership was recorded as a combination of entities under common control, whereby the assets contributed and liabilities assumed are recorded based on their historical carrying values. After the contribution of the Predecessor's business and net assets on May 14, 2013, we have retroactively reported our financial statements to include the historical results of our Predecessor. We accounted for the purchase of Direct Fuels under Financial Accounting Standards Board Accounting Standards Codification (FASB ASC), Statement 805, Business Combinations, whereby the net assets acquired are recorded at fair value on the date of acquisition. The acquisition of Direct Fuels was accounted for as a business combination using the acquisition method of accounting. The financial position and results of operations of Direct Fuels are included in our consolidated financial statements from and as of the date of acquisition. We acquired Direct Fuels to expand our operations, gain new customers, improve earnings, and increase our markets through a larger geographical presence. After completing the acquisition on May 14, 2013, the Partnership owned 100% of Direct Fuels. We funded the acquisition with a combination of cash, issuance of common units and assumption of debt.

For periods prior to our IPO, the accompanying consolidated financial statements and related notes present the historical accounts of the Predecessor. To the extent they relate to periods prior to the IPO, the results are not necessarily indicative of the actual results of operations that might have occurred if we had operated as a combined entity during that pre-IPO period.

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

Emerging Growth Company

We are an "emerging growth company," as defined in the Jumpstart our Business Startups Act of 2012. As such, we have elected to delay adoption of new or revised accounting standards until such time that the standards would be otherwise apply to private companies, as allowed for emerging growth companies, for as long as we are an emerging growth company.

Acquisition

On May 14, 2013, we acquired Direct Fuels from Direct Fuels Partners, L.P. for $98.3 million, in order to expand our operations, gain new customers, improve earnings, and increase our markets through a larger geographical presence. Direct Fuels operates a motor fuel terminal and transmix processing facilities in Texas. Direct Fuels' identifiable assets acquired and liabilities assumed by us were recognized based upon the fair values determined on the date of acquisition.

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We determined the fair values of Direct Fuels property, plant and equipment as well as its identifiable intangible assets with assistance from an independent third-party appraisal expert. Our assessment of the fair value of the assets acquired and liabilities assumed as of May 14, 2013 indicates that the consideration given exceeded the fair value of net identifiable assets acquired. Our assessment indicated that goodwill, the excess of consideration over the fair value of identifiable assets acquired, is $29.3 million. The primary factor that gives rise to goodwill is the premium we were willing to pay to expand our operations into the geographical territories currently served by Direct Fuels. The ability to expand our operations encompasses gaining access to new customers combined with the improved margins attainable through increased market exposure. Additionally, the goodwill is attributable to the value of Direct Fuels' assembled workforce, including a management team, as well as synergies expected to arise through the streamlining of operations.

The reconciliation of fair values of the assets acquired and liabilities assumed related to the Direct Fuel purchase price follows ($ in thousands):

The consideration for the Direct Fuels acquisition totaled $98.3 million. In May 2013, we paid $22.9 million in cash, issued 3,180,612 common units with a fair value totaling $53.7 million, and assumed $21.7 million in long-term debt. The accounts receivable acquired represent the gross contractual amounts and are stated at fair market value. Subsequent to May 14, 2013, we have collected the accounts receivable in the table above. Prior to the acquisition, Direct Fuels declared a cash dividend totaling $11.5 million that was payable from cash and accounts receivable. The $11.5 million dividend payable is a pre-IPO distribution and was paid after the acquisition.

We attributed $45.1 million to intangible assets associated with Direct Fuels' customer relationships, long-term supply and transportation contracts, and a non-compete agreement. We amortize the customer relationships using an accelerated method (based on expected future cash flows) and the other intangibles using straight-line method over their estimated useful lives. The useful lives range as follows: (i) customer relationships, 15 years; (ii) long-term supply and transportation assets, 3 to 54 months; and (iii) non-compete agreement, 4 years.

In 2013, we expensed $1.5 million of transaction costs associated with the acquisition of Direct Fuels. We reported these costs as IPO transaction-related costs within operating expenses. For the period May 14, 2013 (date of acquisition) through December 31, 2013, Direct Fuels' revenues totaled $218.2 million and it reported a net loss of $1.5 million.

The following unaudited pro forma financial information presents the combined results of operations of the Partnership and Direct Fuels as if the transaction had occurred on January 1, 2012. The pro forma

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information is not necessarily indicative of what the results of operations actually would have been had the acquisition been completed on January 1, 2012. In addition, the unaudited pro forma financial information is not indicative of, nor does it purport to project, our future operating results. The unaudited financial information excludes acquisition and integration costs and does not give effect to any estimated and potential cost savings or other operating efficiencies, if any, that might result from the acquisition.

Deconsolidation of Subsidiary

On September 29, 2011, AEC deconsolidated its 100% owned subsidiary W.C. Rice Oil Co., Inc. ("WCRO") by distributing its 100% ownership of WCRO to its owners and ceased including WCRO's operations in its consolidated financial statements on that date.

Prior to deconsolidation, WCRO conducted marketing efforts to sell and distribute gasoline and diesel products to wholesale, industrial, and commercial accounts. These activities were transferred to AEC prior to deconsolidation. In addition, WCRO sold substantially all of its tangible, long-lived assets (consisting of trucks, office equipment and leasehold improvements) to AEC for an amount that approximated net book value at the date of transfer.

At deconsolidation, the net deficit of WCRO was $0.4 million, consisting primarily of cash, other current assets, land, and federal excise taxes payable. This deficit was distributed at an amount that approximated fair value, based on management's assessment of fair values. This transaction was treated as a distribution to owners. We reduced our net deficit by $0.4 million and did not record a gain or loss on the transaction. Since AEC continued WCRO's activities, this has not been presented as discontinued operations.

2.     SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

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

Restricted Cash and Equivalents

We are required under agreements with our chief executive officer ("CEO") and an officer in our Sand segment (the "Sand Officer") to establish and maintain Rabbi Trusts which are used to fund deferred compensation as described in the agreements. Restricted cash and equivalents are invested in short-term instruments at market rates; therefore the carrying values approximate fair value.

Accounts Receivable and Allowance for Doubtful Accounts

Trade accounts receivable are recognized at their invoiced amounts and do not bear interest. We maintain an allowance for doubtful accounts for estimated losses resulting from the inability of our customers to make required payments. We estimate our allowances for doubtful accounts based on specifically identified

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amounts that are believed to be uncollectible. If the financial condition of our customers were to deteriorate, resulting in an impairment of their ability to make payments, additional allowances for doubtful accounts might be required. After all attempts to collect a receivable have failed, the receivable is written off against the allowance for doubtful accounts. The allowance for doubtful accounts was $0.3 million at December 31, 2013, and $0.1 million at December 31, 2012.

Inventories

Finished goods inventories consist of dried sand and refined motor fuel products. All inventories are stated at the lower of cost or market using the average cost method. Raw materials inventories consist of wet-sand stockpiles and transmix feedstock. Raw materials inventories are stated at the lower of cost or market using the average cost method. Overhead in our Sand segment is capitalized at an average rate per unit based on actual costs incurred. Our Fuel segment does not capitalize overhead to its refined transmix inventory because turnover is high and the quantities are generally modest in comparison to our finished fuel inventories we purchase from third party refiners.

Accounting for Renewable Identification Numbers

The Fuel segment is required to comply with federal laws that regulate biofuels and renewable identification numbers ("RINs"). RINs are serial numbers assigned to biofuels for the purpose of tracking its production, use, and trading as required by the U.S. Environmental Protection Agency (the "EPA") under its Renewable Fuel Standard implemented according to the Energy Policy Act of 2005. Generally, companies that refine petroleum-based fuels are obligated to meet certain quotas based on the volume of fuel they introduce into the marketplace. We are required to satisfy these obligations to the extent previously non-certified fuels are included or introduced into transmix feedstock. We account for these direct obligations as a liability until satisfied. As of December 31, 2013 and 2012, accrued liabilities include $41 thousand and $0, respectively, for obligations under the Energy Policy Act of 2005.

The Fuel segment routinely purchases ethanol for blending with gasoline. To a lesser extent, the Fuel segment purchases biodiesel for blending with diesel. We have the option to purchase these biofuels with or without RINs, but most biofuels are only available for purchase with RINs. The price suppliers charge to us for biofuels with RINs is somewhat higher than a price that would be charged for product without RINs. We generally purchase the biofuels with RINs. We account for RINs in a manner similar to the purchase of conventional fuels. On a monthly basis, we sell most of our RINs under a contractual arrangement with a major refiner. For RINs that remain unsold at the end of an accounting period, we value this asset at an amount that approximates net realizable value, recording the offset as a reduction in cost of goods sold. When these RINs are sold, we record the sale as a reduction of costs of goods sold instead of additional revenue, effectively offsetting the charge to cost of goods sold when the RINs asset is relieved. As of December 31, 2013 and 2012, prepaid expenses and other current assets include RINs valued at $0.3 million and $0.6 million, respectively.

Direct Financing Lease Receivable

In July 2012, we entered into an agreement with a third party in which we built a wet sand processing plant and the third party agreed to operate the plant for the purpose of processing wet sand. We pay a specified fee per ton of processed sand purchased by us for the ten-year term of the agreement, and the full amount is recorded as raw materials cost. In turn, we withhold a fixed fee per ton as payment by the third party for eventual transfer of ownership of the plant. The initial cost of the plant totaling $2.7 million was recognized as a direct financing lease receivable in September 2012. The fee from the third party will no longer be withheld when we recover the full cost of the plant, including interest at 6.0% per annum. We anticipate receiving the full amount of this receivable within two years from inception of the agreement and, accordingly, we classified a portion of the receivable as a current asset based on our anticipated processed sand purchases. We routinely monitor compliance with payment terms and assess the account for collectability.

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Property, Plant and Equipment, net

We recognize purchases of property, plant and equipment at cost, including capitalized interest. Maintenance, repairs and renewals are expensed when incurred. Additions and significant improvements are capitalized. Disposals are removed at cost less accumulated depreciation and any gain or loss from dispositions is recognized in income. We capitalized $0, $1.0 million and $0.2 million of interest on construction of assets for the years ended December 2013, 2012 and 2011, respectively.

Depreciation of property, plant and equipment other than mineral reserves is provided for on a straight-line basis over their estimated useful lives. We recognized $13.7 million, $8.8 million and $6.4 million of depreciation expense for 2013, 2012 and 2011, respectively.

Mineral reserves are initially recognized at cost, which approximates the estimated fair value as of the date of acquisition. The provision for depletion of the cost of mineral resources is computed on the units-of-production method. Under this method, we compute the provision by multiplying the total cost of the mineral resources by a rate arrived at dividing the physical units of sand produced during the period by the total estimated mineral resources at the beginning of the period. Depletion expense for 2013, 2012 and 2011 totaled $29,070, $46,221 and $46,574, respectively.

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

Impairment or Disposal of Long-Lived Assets

In accordance with FASB ASC 360-10-05, Impairment or Disposal of Long-Lived Assets, long-lived assets such as property, plant, and equipment, and intangible assets subject to amortization are reviewed for impairments whenever events or changes in circumstances indicate that the related carrying amount may not be recoverable. If circumstances require a long-lived asset be tested for possible impairment, we first compare undiscounted cash flows expected to be generated by an asset to the carrying value of the asset. If the carrying value of the long-lived asset is not recoverable on an undiscounted cash flow basis, impairment is recognized to the extent that the carrying value exceeds its fair value. Assets to be disposed of are reported at the lower of the carrying amount or fair value less selling costs. The recoverability of intangible assets subject to amortization is also evaluated whenever events or changes in circumstances indicate that the carrying value of the assets may not be recoverable. In management's opinion, no impairment of long-lived assets exists at December 31, 2013 and 2012.

In 2011, our management made a decision to sell a parcel of land which was not a revenue generating asset. The expected net proceeds were less than the net book value of the asset at that time, resulting in the recognition of an impairment loss of $0.8 million and adjustment of the carrying value of the land to the fair value less cost to sell in 2011. The asset was sold in 2012 for the expected amount.

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Intangible Assets Other Than Goodwill

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

We recognized $7.1 million, $0.3 million and $0.4 million of amortization expense for 2013, 2012 and 2011, respectively.

Goodwill

Goodwill is not amortized and represents the excess purchase price of the Direct Fuels acquisition over the estimated fair value of the net identifiable assets acquired. As of December 31, 2013 and 2012, goodwill totaled $29.3 million and $0, respectively. As of December 31, 2013, goodwill is associated with our Fuel segment. In accordance with GAAP, we perform impairment testing of goodwill assets annually, or more frequently if indicators of impairment exist in interim periods. The impairment test for goodwill uses a two-step process, which is performed at the entity level (the reporting unit). Step one compares the fair value of the reporting unit (calculated using the enterprise value-market capitalization approach) to its carrying value. If the carrying value exceeds the fair value, there is a potential impairment and step two must be performed. Step two compares the carrying value of the reporting unit's goodwill to the implied fair value (i.e., the fair value of the reporting unit less the fair value of the unit's assets and liabilities, including identifiable intangible assets). If the carrying value of goodwill exceeds its implied fair value, we record the excess as an impairment charge to earnings.

We performed our annual assessment of goodwill in the fourth quarter of 2013, and determined during Step one that the fair value of the reporting unit (our Fuel segment) exceeds its carrying value. Therefore, it was not necessary to perform Step two of the analysis.

Other Assets, Net

Deferred financing costs

Financing costs that are directly and incrementally associated with new borrowings are capitalized and amortized over the term of the related debt using the straight-line method, which approximates the effective interest method. The balances of net deferred financing costs were $3.5 million and $3.4 million as of December 31, 2013 and 2012, respectively.

Deferred public offering costs

At December 31, 2012 we had recorded $3.7 million of direct and incremental professional fees incurred related to our IPO. We initially deferred these costs and subsequently charged them against IPO proceeds in 2013.

Derivative Instruments and Hedging Activities

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

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Asset Retirement Obligations

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

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

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

Changes in the asset retirement obligations are as follows:

Revenue Recognition

Our revenue is recognized when persuasive evidence of an arrangement exists, delivery of products has occurred, the sales price charged is fixed or determinable, and collectability is reasonably assured. This generally means that we recognize revenue when our products leave our facilities. Sand and fuel are generally transported via railcar or trucking companies hired by the customer.

We sell some of our Sand segment products under short-term price agreements or at prevailing market rates. A significant portion of our Sand segment revenues are realized through take-or-pay supply agreements with large oilfield services companies. The initial terms of these contracts expire between 2013 and 2021. These agreements define, among other commitments, the volume of product that our customers must purchase, the volume we must provide and the price that we will charge, as well as the rate that our customers will pay. Prices under these agreements are generally fixed and subject to adjustment, upward or downward, only for certain changes in published producer cost indices or market factors. With respect to the take-or-pay arrangements, if the customer is unable to carry forward minimum quantity deficiencies, we recognize Sand segment revenues to the extent of the minimum contracted quantity, assuming payment has been received or is reasonably assured. If deficiencies can be carried forward, receipts in excess of actual sales are recognized as deferred revenues until product is actually delivered or the right to carry forward minimum quantities expires.

For customers that advance monies to the Sand segment under a contractual arrangement, we record revenue at the time of product delivery. At delivery, we reduce the liability "advances from customers" and record the revenue. As of December 31, 2013, we have satisfied the customer advances in full.

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We recognize Fuel segment revenue related to our terminals, reclamation, transportation services, and sales of motor fuels, net of trade discounts and allowances, in the reporting period in which the services are performed and motor fuel products are transferred from our terminals, title and risk of ownership pass to the customer, collection of the relevant receivable is probable, persuasive evidence of an arrangement exists and the sales price is fixed or determinable.

Motor Fuel Taxes

We report excise taxes on motor fuels on a gross basis. For the years ended December 31, 2013, 2012 and 2011, excise taxes included in fuel revenues and cost of fuel totaled $47.0 million, $37.8 million and $19.6 million, respectively.

Equity-Based Compensation and Equity Incentive Plan

We recognize expenses for equity-based compensation based on the fair value method, which requires that a fair value be assigned to a unit grant on its grant date and that this value be amortized over the grantees' required service period. Restricted and phantom units have a fair value equal to the fair market price of the common units on the date of the grant. We amortize the fair value of the restricted and phantom units over the vesting period using the straight-line method. The fair value of a certain equity award to a key employee was determined using a Monte Carlo simulation. We calculated a forfeiture rate to estimate the equity-based awards that will ultimately vest based on types of awards and historical experience. For performance-based awards, we make estimates as to the probability of the underlying performance being achieved and record expense if the performance will probably be achieved.

Environmental Costs

Environmental costs are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. We capitalize expenditures that extend the life of the related property or mitigate or prevent future environmental risk. We record liabilities when site restoration and environmental remediation, cleanup and other obligations are either known or considered probable and can be reasonably estimated. Such estimates require judgment with respect to costs, time frame and extent of required remedial and clean-up activities and are subject to periodic adjustments based on currently available information. At December 31, 2013 and 2012, we had no accrued expenses related to environmental costs.

Provision for Income Taxes

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

We are responsible for our portion of the Texas margin tax that is included in our subsidiaries' consolidated Texas franchise tax returns. The margin tax qualifies as an income tax under GAAP, which requires us to recognize the impact of this tax on the temporary differences between the financial statement assets and liabilities and their tax basis attributable to such tax.

Emerge Energy Distributors Inc. ("Distributor"), our subsidiary that supports the Fuel segment, reports its income, expenses, gains, and losses as a corporation and is subject to both federal and state income taxes. Our provision for income taxes relates to: (i) Texas margin taxes for the Partnership and for Distributor, as well as (ii) federal and state income taxes for Distributor.

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Fair Value of Financial Instruments

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

Our financial instruments consist primarily of cash and cash equivalents, restricted cash and equivalents, accounts receivable, accounts payable and debt instruments. The carrying amounts of cash and cash equivalents, restricted cash and cash equivalents, accounts receivable and accounts payable are representative of their fair values due to their short maturities. As of December 31, 2013, the carrying amount for our $200 million senior secured revolving credit facility approximates fair value because the underlying instrument includes provisions that adjust our interest rates based on current market rates.

Concentration of Credit Risk

Financial instruments that potentially subject us to concentration of credit risk are cash and cash equivalents and trade accounts receivable. Our cash and cash equivalents were fully insured as of December 31, 2012 due to a temporary federal program in effect from December 31, 2010 through December 31, 2012. Under the program, there is no limit to the amount of insurance for eligible accounts. Beginning in 2013, insurance coverage reverted to $250,000 per depositor at each financial institution and certain of our cash balances did exceed federally insured limits as of December 31, 2013. We maintain our cash and cash equivalents in financial institutions we consider to be of high credit quality.

We provide credit, in the normal course of business, to customers located throughout the United States and Canada. We perform ongoing credit evaluations of our customers and generally do not require collateral. In addition, we regularly evaluate our credit accounts for loss potential.

Our largest customer balance represented 14% of our net accounts receivable balance as of December 31, 2013 while the top two customer balances represented 15% and 14% as of December 31, 2012, respectively. No other customer balance exceeded 10% of the total net accounts receivable balance as of December 31, 2013 and 2012.

No individual customer represented more than 10% of revenues for the year ended December 31, 2013 while one customer individually represented 15% and 10% of revenues for the years ended December 31, 2012 and 2011, respectively.

Segments

We operate our business in two reportable segments.

•

The Sand segment consists of the production and sale of various grades of industrial sand primarily used in the extraction of oil and natural gas, as well as the production of building products and foundry materials.



•

The Fuel segment operates two terminals and two transmix processing facilities that are located in the Dallas-Fort Worth, Texas area and Birmingham, Alabama. In addition to refining transmix, the Fuel segment sells a suite of complementary fuel products and services, including third-party terminaling services, the sale of wholesale petroleum products, certain reclamation services (which consist primarily of tank cleaning services) and blending of renewable fuels.

For operations and other Partnership activities not managed through our two operating segments, these items of income, if any, and costs are presented herein as "corporate." Our chief operating decision maker

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("CODM") is our chief executive officer. The CODM allocates resources and assesses performance of the business based on segment income or loss as presented in Note 15.

Seasonality

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

Other Reclassifications

We reclassified certain prior period financial statement balances to conform to the current period presentation. These reclassifications had no effect on net income or loss.

Recent Accounting Pronouncements

There have been no recent accounting pronouncements that have had or will have a material impact on our financial position or results of operations.

3.     INVENTORIES

Inventories consisted of the following:

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4.     PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment consisted of the following:

During 2011, we sold certain plant and equipment to a third party with a net book value of $1.1 million in a sale-leaseback transaction resulting in a non-cash reduction of the capital lease liability by the same amount.

5.     INTANGIBLE ASSETS OTHER THAN GOODWILL

Our intangible assets other than goodwill consisted of the following at December 31, 2013 and 2012:

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The following table presents the estimated future amortization expense related to intangible assets through 2018:

6.     ACCRUED LIABILITIES

Accrued liabilities consisted of the following:

7.     ADVANCES FROM CUSTOMERS

During 2011, we entered into agreements with three customers (the "Sand Supply Agreements") that included customer prepayment provisions. We received advance payments from three customers in the following amounts: customer 1: $8,000,000; customer 2: $5,000,000; customer 3: $3,000,000. The repayment periods ranged from two to three years for each of the Sand Supply Agreements.

We agreed to repay the advance payments, including interest, during the repayment period by applying against the full invoiced amount a credit ranging from $10.00 to $11.50 per ton, depending on the grade of sand being purchased.

The above obligations were secured by letters of credit that were issued by an affiliate of our majority owner through a financial institution at a percentage of the original principal balance of 60%, 50% and 100% for customers 1, 2 and 3, respectively. The letters of credit were reduced proportionally on a quarterly or semi-annual basis based on principal payments made as of each respective contract annual effective date. As of December 31, 2013, we had repaid all customer advances in full.

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8.     LONG-TERM DEBT

Following is a summary of our long-term debt as of December 31, 2013 and 2012:

Revolving Credit Facility

On May 14, 2013, we entered into a $150 million revolving credit and security agreement (the "Credit Agreement") among Emerge Energy Services LP, as parent guarantor, each of its subsidiaries, as borrowers (the "Borrowers"), and PNC Bank, National Association, as administrative agent and collateral agent. We subsequently amended the Credit Agreement to revise certain definitions and to increase the commitment amount. The Credit Agreement, as amended, provides for a $200 million variable rate senior secured revolving credit facility (the "new credit facility") which was available to repay our existing indebtedness on the closing date of the IPO, to fund fees and expenses incurred in connection with the IPO and the credit facility, and for general business purposes, including working capital requirements, capital expenditures, permitted acquisitions, making debt payments (but not prepayments) when due, and making distributions and dividends. In addition, the Credit Agreement includes a sublimit of up to $15 million for the issuance of letters of credit. Substantially all of the assets of the Borrowers are pledged as collateral under the Credit Agreement. The new credit facility matures on May 14, 2018.

Loans under the new credit facility bear interest at our option at either:

•

a Base Rate (as defined in the Credit Agreement), which will be the base commercial lending rate of PNC Bank, as publicly announced to be in effect from time to time, plus an applicable margin ranging from 1.75% to 2.50% based on our total leverage ratio; or



•

LIBOR plus an applicable margin ranging from 2.75% to 3.50% based on our total leverage ratio.

We also incur a commitment fee of 0.375% on committed amounts that are neither used for borrowings nor under letters of credit.

We initially borrowed $112.7 million to (i) make distributions of $17.0 million to SSH and to fund the cash payment in the Direct Fuels acquisition amounting to $22.2 million; and, (ii) repay $73.5 million of existing SSH debt. As part of the original Credit Agreement, we incurred $3.6 million of direct financing costs for

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professional and legal fees, which we recorded as deferred financing cost. We subsequently incurred $0.1 in bank fees related to amendments that were also recorded as deferred financing cost.

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

•

a fixed charge coverage ratio (as defined in the Credit Agreement) of not less than 1.10 to 1.00; and



•

total leverage ratio (as defined in the Credit Agreement) of not greater than 3.00 to 1.00. The requirement to maintain the total leverage ratio is subject an increase to 3.50 to 1.00 in connection with certain permitted acquisitions.

At December 31, 2013, we were in compliance with our loan covenants and had undrawn availability under this credit facility totaling $90.3 million. At December 31, 2013, our outstanding borrowings under the Credit Agreement bore interest at a weighted-average rate of 2.94%.

Senior Secured Credit Facilities

Prior to our IPO, we maintained several senior secured credit facilities. In our Sand Segment, we maintained a $60 million credit facility that was comprised of a $30 million Term A note, a $20 million capital expenditure Term B line of credit and a $10 million operating revolving credit facility. All facilities accrued interest at LIBOR plus 425 basis points. At the time of the IPO, we had $27.0 million drawn on the Term A note, $20.0 million drawn on the Term B note and $8.0 million drawn on the operating revolving credit facility. The revolving credit facility was secured by substantially all of our Sand segment accounts receivable and inventory and the term loans had first lien positions on all the remaining assets in our Sand segment. The senior secured credit facilities required us to maintain certain debt covenants related to leverage and tangible net worth. We repaid Sand segment amounts outstanding under the revolving credit and senior term loan facilities in full at the closing of our IPO. These repayments totaled $55.1 million and resulted in a $2.9 million loss on extinguishment of debt.

In our Fuel segment, we maintained a senior secured credit facility consisting of a $15 million revolving credit facility and a term loan that, as of May 13, 2013, had a carrying value of $20.3 million. Substantially all of our Fuel segment assets collateralized both facilities. The maturity date of the revolver and term loan was April 1, 2015. The revolver loan and term loan accrued interest monthly at a rate equal to either (a) the base commercial lending rate of the bank as publicly announced plus applicable margin or (b) a rate equal to LIBOR plus applicable margin, which was tied to our financial performance. The same credit agreement had a term loan prepayment arrangement whereby we were required to remit 50% of excess cash flow beginning thirty days after delivery of the 2012 audited financial statements to the senior lenders and continuing annually thereafter until maturity. Based on 2012 financial results and the credit agreement terms controlling the prepayment, we did not owe the conditional prepayment. We repaid all amounts outstanding under the revolving credit and senior term loan facilities at the closing of the IPO. On May 14, 2013, we repaid the outstanding balances for both the revolver and term loan facility totaling $15 million and $18.2 million, respectively.

Troubled Debt Restructuring

On April 1, 2011, AEC entered into an agreement with senior lenders to amend its existing credit agreement. The amendment waived the events of default, rescinded the acceleration notice, modified the terms of repayment, forgave approximately $6.4 million of principal and interest, required the members to contribute $4.0 million of cash as permanent capital, required the grant of a 10% equity interest to the senior lenders, modified the loan covenants, and established a contingent prepayment based on cash flows as defined by the amendment. We accounted for this debt restructuring as troubled debt restructuring ("TDR").

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The TDR resulted in a gain on debt restructuring for the year ended December 31, 2011 of $0.5 million. The TDR accounting resulted in differences between the carrying value of term debt and amounts owed the senior lenders at December 31, 2012 and 2011. The carrying value of term debt was $20.8 million and $22.0 million at December 31, 2012 and 2011, respectively. The actual term loan amounts due the senior lenders totaled $18.4 million and $18.7 million at December 31, 2012 and 2011, respectively. In addition, TDR accounting required that interest payments reduce the carrying value of term debt in lieu of a charge to earnings. Interest payments reduced the carrying value of term debt $0.9 million and $0.7 million for the years ended December 31, 2012 and 2011, respectively.

On May 14, 2013, we repaid outstanding amounts due under this credit facility to the extent of $33.4 million. This amount included a $15.0 million revolver, the restructured term loan, and accrued interest through date of payoff. The payoff of these debts resulted in a $2.0 million gain on early extinguishment of debt.

Second Lien Credit Agreement

On September 7, 2012, we entered into a third amended and restated credit agreement with a third party and a related party which was scheduled to mature on March 7, 2017. As of the time of the IPO, we had $45.3 million in outstanding borrowings bearing cash and "in-kind" interest at a rate of 18% per annum. We repaid all second lien term loans in full at the closing of our IPO.

Third Lien Credit Agreement

On September 7, 2012, we entered into a first amended and restated credit agreement with an affiliate of the owner of our general partner and other lenders named therein. As of the time of the IPO, we owed $5.3 million under this arrangement. The credit agreement governed our third lien term loan, which was scheduled to mature on September 7, 2017 and bore interest at a rate of 0% per annum. We repaid the third lien term loan in full at the closing of our IPO.

Direct Fuels

As described above, we assumed senior debt associated with the purchase of Direct Fuels. On May 14, 2013, we repaid all amounts outstanding totaling $21.7 million.

Other Long-Term Debt

From time to time, we incur additional debt to finance specific equipment purchases. Total outstanding principal amounts of such borrowings were $0.2 million and $1.2 million as of December 31, 2013 and 2012, respectively.

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9.     COMMITMENTS AND CONTINGENCIES

Contractual Obligations at December 31, 2013

Sand Purchase Commitments and Railway Shipping Commitments

In connection with the capital lease liability discussed below, as well as the direct financing lease receivable, we maintain minimum annual purchase commitments with two third-party wet sand suppliers with original terms of five and ten years, respectively. Additionally, in May 2012 we entered into a railway shipping agreement requiring us to pay a shortfall penalty if minimum annual tonnage levels are not shipped for a term of 10 years commencing on December 1, 2012. For the years ended December 31, 2013, 2012, and 2011, we met or exceeded our minimum commitment requirements under all of our purchase agreements.

Operating Leases

We lease rail cars, rail track, locomotives, office and terminal facilities, land, and equipment with various terms in connection with our daily operations. Operating lease expense for the years ended December 31, 2013, 2012 and 2011 totaled $6.0 million, $0.9 million and $0.4 million, respectively.

Royalty Commitments

We maintain various royalty agreements related to the extraction of sand in Wisconsin, of which certain agreements require minimum payments if minimum volumes are not extracted on an annual basis. For the years ended December 31, 2013, 2012, and 2011, we met or exceeded our minimum commitment requirements under all of our royalty agreements.

Capital Lease Liability

In April 2011, we entered into an agreement with a third party to mine and process mineral resources at our New Auburn location for a specified fee per ton for five years, after which we will acquire ownership of the New Auburn wet plant without paying additional consideration. This agreement qualifies as a capital lease obligation and the specified fee per ton includes amounts paid to the third party for i) the extraction of sand, ii) operating costs associated with operating the wash plant and iii) an estimated amount per ton as a lease payment. Minimum future lease payments, based on estimated future production, under capital lease as of December 31, 2013 total $4.0 million, of which $0.6 million represents interest. Due to higher than anticipated purchase volumes, we anticipate extinguishing our capital lease liability during the year

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ending December 31, 2014. As a result, our cost of sand will likely increase as the contractual price we pay per ton remains relatively consistent during the remaining term of the contract, however, our total cash flows will not be impacted due to this change in classification.

Other Commitments and Contingencies

Plant Construction Commitment

On January 2, 2014, we signed a construction agreement with a third party to build a sand wash plant that we anticipate to be completed during 2014. The total contracted price is $8.3 million. We paid $1.6 million as a deposit on January 3, 2014.

Employment Agreement, Deferred Compensation, and Rabbi Trusts

Prior to our IPO, we had a long-term incentive compensation program (the "LTIC") with our CEO and the Sand Officer under which additional compensation may be paid based on certain events, as defined in the agreement. Before May 14, 2013, there were no amounts due under these agreements. On May 29, 2013, we terminated these agreements. In consideration for terminating the LTIC agreements, we agreed to pay the CEO $4.3 million and the Sand Officer $2.1 million in cash within ten days of May 29, 2014. On May 30, 2013, we deposited $6.4 million into two separate trust accounts under an informal funding arrangement known as Rabbi Trusts. We account for these amounts in accordance with FASB ASC 710, Compensation—General, as it relates to arrangements where compensation is both earned and held in Rabbi Trusts. At December 31, 2013, trust assets were invested in money market funds and the carrying value approximated fair value. We expensed the combined total ($6.4 million) of this deferred compensation during the year ended December 31, 2013. As of December 31, 2013, the accrued deferred compensation expense remains unpaid totaling $6.7 million including $0.4 million of accrued quarterly distribution equivalent rights.

Excise Tax Penalty

In 2012, we received an IRS notice of a penalty totaling $340,000 due to failure to file terminal operator reports in electronic format. We filed these returns in paper format. Management protested the audit findings through IRS appeal channels. Management placed the IRS on notice that it plans to claim exception from penalty due to reasonable cause. The IRS appeal conference has not been scheduled. 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.

Property Value Assurance

On May 13, 2013, we entered into a mining agreement with the Town of Sioux Creek, Wisconsin ("Sioux Creek") that addresses local regulations related to the operation of our future facility in Sioux Creek. The agreement expires at the end of twenty years. The agreement covers hours and days of operation, royalty payments, control of light and noise, and a property value guaranty or assurance ("PVA"). The PVA provision requires our guaranty of certain owners' property values, as defined in Sioux Creek's ordinance which could require us to make future payments to the specified property owners, if any. The ordinance states that any adjoining property owner, that was an owner prior to commencement of operations, that markets their property for third-party sale subsequent to commencement of operations may have their property appraised by a real estate appraiser in the State of Wisconsin to determine fair market value as if the mining operation did not exist (if the mine operator and land owner do not agree on the appraiser both may chose an appraiser and the average of the two appraisals shall determine fair market value). Certain provisions allow the mine operator to purchase the property or to reimburse the landowner for any shortfall between the selling price and the fair market value established by appraisal within a six month timeframe.

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On November 9, 2013, we entered into a mining agreement with the Town of Auburn, Wisconsin ("Auburn") that addresses local regulations related to sand mining and sand processing activities at our New Auburn, Wisconsin facility. The agreement expires on December 31, 2043. The agreement covers hours of operation, use of roads, control of light and noise, air quality and fugitive dust, control of waste materials, groundwater standards, and a PVA. The PVA provisions include our guaranty of certain owners' property values, as defined in the agreement, and set forth the terms by which we could be required to make future payments to the specified property owners, if any. We are required to pay the property owner the excess of fair market value over selling price, if any. In addition, if the owner's property fails to sell after 270 days from the date listed for sale, we are obligated to purchase the property for fair market value. The agreement defines fair market value using one of two methods: (i) the value identified in the Town's 2011 tax rolls plus 10%; or, in the event the property owner believes the other method does not accurately reflect fair market value, (ii) a then current appraisal prepared by a third party expert using comparable values for similar properties not located within one-quarter mile of a mine site. In the event the property owner sells the property for an amount exceeding fair market value, we are under no obligation to make payment. The PVA provision runs with the land and is binding on the property owners, us, and their heirs, grantees, representatives, successors, and assigns.

We have not accrued a liability related to the PVAs noted above as management does not believe a future payment is probable or reasonably estimable as of December 31, 2013.

Counterparty Risk

The Sand segment routinely purchases raw sand from a supplier located in Wisconsin. We understand from public sources that the supplier may be experiencing financial difficulties. Because we have been unable to verify the validity of this information, we are unable to make a complete and accurate assessment about the precise extent of financial risk, if any, that this supplier is facing. At December 31, 2013, the supplier was custodian of $2.2 million of our raw sand inventory stored on the supplier's property. We do not have security agreements in place that specifically identify the raw sand inventory as assets belonging to us, but it is our opinion that title to the sand has passed to us. In the opinion of management, as of the date of these financial statements, the amounts representing inventories stored at this supplier's site are fully recoverable in the ordinary course of business.

Letters of Credit

On October 25, 2013, we issued a $3.7 million letter of credit to a fuel pipeline common carrier to secure payment for transmix open account purchases and pipeline tariffs. Effective with posting the letter of credit with the pipeline common carrier, the Fuel segment became eligible to transport refined motor fuels and transmix to its facility located in Birmingham, Alabama via pipeline. The letter of credit expires on April 30, 2014.

As of December 31, 2013 and 2012, SSS had an outstanding letter of credit to the favor of Barron County for $258,000. SSS provided this letter of credit to assure performance under the reclamation plan filed with Barron County.

During 2011, affiliates of Insight Equity and LBC Credit Partners, L.P. obtained letters of credit on behalf of SSS to support its obligation to repay $16.0 million in advance payments provided by three sand customers at the time they entered into take-or-pay supply agreements with us. The aggregate balances under these letters of credit were $0 and $6.7 million as of December 31, 2013 and 2012, respectively. See Note 7 for discussion of these advances from customers.

An affiliate of Insight Equity obtained a $1.5 million letter of credit to provide additional security against an equity investment that LBC Credit Partners, L.P. made in SSS after Insight Equity's purchase of Superior Silica Holdings LLC. This letter of credit was retired at the closing of our initial public offering.

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Litigation and Potentially Uninsured Liabilities

We are subject to various claims and litigation arising in the ordinary course of business. We maintain general liability insurance with limits and deductibles that management believes prudent in light of our exposure to loss and the cost of insurance. We had recognized no liabilities as of December 31, 2013 and 2012 related to uninsured claims and litigation, and current uninsured litigation matters are not expected to have a material adverse effect on our financial position, liquidity or results of operations. We expense legal costs related to claims and litigation in the period incurred.

Environmental Matter

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

10.   RELATED PARTY TRANSACTIONS

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

(1)

We do not have any employees. Prior to May 14, 2013, our Predecessor and Direct Fuels had employees assigned directly to their respective operations. On May 14, 2013, our general partner hired all employees of the Predecessor and Direct Fuels. After this date, our general partner manages our human resource assets, including fringe benefits and other employee-related charges. We routinely and regularly reimburse our general partner for any employee-related costs paid on our behalf, and report such costs as operating expenses.

(2)

See Note 8 for a discussion of the second lien credit agreement and the third lien credit agreement.

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(3)

We paid Insight Equity certain IPO transaction-related costs and other general and administrative costs. See discussion of the current services agreement below.

(4)

Prior to May 14, 2013, our Fuel segment paid an affiliated company for leadership services at an annual amount of $250,000 plus bonus for financial performance, if any. Beginning May 14, 2013, these services are being performed by Insight Equity employees and are charged to us through reimbursement process in (1) above.

Agreements with Affiliates

Registration Rights Agreement.    In connection with closing of the IPO, we entered into a Registration Rights Agreement, dated as of May 14, 2013 (the "Registration Rights Agreement"), by and between AEC Resources LLC, Ted W. Beneski, Superior Silica Resources LLC, Kayne Anderson Development Company and LBC Sub V, LLC. Pursuant to the Registration Rights Agreement, we agreed to register for resale the restricted common units of the Partnership (the "Restricted Units") issued to the other parties to the Registration Rights Agreement. We also agreed to file a registration statement providing for resale of the Restricted Units as permitted by Rule 415 of the Securities Act of 1933 no later than July 1, 2014. We also agreed, subject to certain limitations, to allow the holders to sell Restricted Units in connection with certain registered offerings that we may conduct in the future and to provide holders of a specified number of Restricted Units the right to demand that we conduct an underwritten public offering of Restricted Units under certain circumstances. The Registration Rights Agreement contains representations, warranties, covenants and indemnities that are customary for private placements by public companies.

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

11.   EQUITY-BASED COMPENSATION

Effective May 14, 2013, we adopted our 2013 Long-Term Incentive Plan (the "LTIP") for providing long-term incentives for employees, directors, and consultants who provide services to us. The plan is administered by a committee subject to oversight by the board of directors of our general partner (the "Board of Directors"). The committee has delegated authority to: (i) designate participants; (ii) determine types of awards; (iii) determine number of units covered by the award; (iv) determine terms and conditions of awards; (v) determine how and when awards might be settled; and (vi) interpret and administer the plan and take other such actions as might be necessary for the proper administration of the plan. The LTIP provides for the issuance of an aggregate of up to 2,321,968 common units to be granted either as options, restricted units, phantom units, distribution equivalent rights, unit appreciation rights, unit award, profits interest units, or other unit-based award granted under the plan. As of December 31, 2013, we had granted awards totaling 1,148,235 units that represent a combination of restricted and phantom units, all of which are to be settled through issuance of limited partner common units. Our CEO and the Sand Officer also participate in the LTIP plan. On May 14, 2013, we granted 530,588 and 265,294 phantom units to our CEO and Sand Officer, respectively. Half of these phantom units vest in one year, and the remaining half in the year after. The agreements covering the CEO and the Sand Officer entitle them to receive dividends in an amount equal to any distributions to our common unitholders whether or not such phantom units are vested. Independent director restricted units vest after one year. For other employees, we assume a 30-month vesting period for phantom unit grants, which represents management's estimate of the amount

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of time until all vesting conditions have been met. Regarding distributions for independent directors and other employees, distributions are credited to a distribution equivalent rights account for the benefit of each participant and become payable generally within 45 days following the date of vesting. As of December 31, 2013, the unpaid liability for distribution equivalent rights totaled $0.4 million.

The following table summarizes awards granted during the post-IPO period of May 14, 2013 through December 31, 2013. The outstanding balance at December 31, 2013 represents total awards since IPO. During the year ended December 31, 2013, there was a forfeiture of 50,000 phantom units.

For the year ended December 31, 2013, we recorded non-cash compensation expense relating to equity-based compensation of $5.7 million in selling, general and administrative expenses. As of December 31, 2013, the unrecognized compensation expense related to the grants discussed above amounted to $13.0 million to be recognized over a weighted average of 1.5 years.

12.   IPO TRANSACTION-RELATED COSTS

We incurred generally non-recurring expenses related directly to the IPO. These costs consist primarily of incentive compensation and payroll-related costs paid to management. In addition, we incurred indirect legal, accounting, and other professional fees associated with the IPO transaction not related to the issuance of equity and debt. We reported these amounts as an operating expense for the year ended December 31, 2013.

There were no similar expenses prior to 2013. The following table summarizes these costs (in thousands):

13.   INCOME TAXES

Provision for Income Taxes

Our provision for income taxes relates to: (i) Texas margin taxes for the Partnership and for Distributor, as well as (ii) federal and state income taxes for Distributor. For federal income tax purposes, we report our income, expenses, gains, and losses as a partnership not subject to income taxes. As such, each partner is responsible for his or her share of federal and state income tax. Net earnings for financial statement

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purposes may differ significantly from taxable income reportable to each partner because of differences between the tax basis and financial reporting basis of assets and liabilities. Distributor reports its income, expenses, gains, and losses as a corporation and is subject to both federal and state income taxes.

The composition of our provision for income taxes follows:

Effective Income Tax Rate

Distributor began operations in 2013. For the year ended December 31, 2013 Distributor's effective income tax rate was 33%. For Distributor, there were no significant differences between book and taxable income. We are responsible for our portion of the Texas margin tax that is included in our subsidiaries' consolidated Texas franchise tax returns. For our operations in Texas, the effective margin tax rate is approximately 0.5% as defined by applicable state law. The margin tax qualifies as an income tax under GAAP, which requires us to recognize the impact of this tax on the temporary differences between the financial statement assets and liabilities and their tax basis attributable to such tax.

14.   EARNINGS PER COMMON UNIT

We compute basic net income per unit by dividing net income by the weighted-average number of common units outstanding including participating securities. Participating securities include unvested equity-based payment awards that contain non-forfeitable rights to distributions. For these purposes, grants to our CEO (530,588 units) and the Sand Officer (265,294 units) are deemed participating securities.

Diluted net income per unit is computed by dividing net income by the weighted-average number of common units outstanding, including participating securities, and increased further to include the number of common units that would have been outstanding had potential dilutive units been exercised. The dilutive effect of restricted units is reflected in diluted net income per unit by applying the treasury stock method. The participating phantom units with non-forfeitable rights to distributions are not considered in computations under the treasury stock method to derive potentially dilutive units outstanding. At December 31, 2013, there were no anti-dilutive units outstanding.

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Basic and diluted earnings per unit are computed as follows:

15.   SEGMENT INFORMATION AND GEOGRAPHICAL DATA

Segment Information

We operate our business through two reportable business segments:

•

Sand - the production and sale of various grades of sand primarily used in the extraction of oil and natural gas and the production of numerous building products and foundry materials.



•

Fuel - the refining of transmix, distribution of finished fuel products, terminal and reclamation activities, and refining of biodiesel.

Segments have been identified based on how management makes operating decisions, assesses performance and allocates resources. Certain items are reviewed by our management on a consolidated basis, and are therefore presented as corporate income rather than segment income:

•

general and administrative costs related to corporate overhead, such as headquarters facilities and personnel, as well as equity-based compensation;



•

certain other operating costs such as IPO transaction-related; and



•

non-operating items such as interest, other income and income taxes.

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Although not used by management in its performance monitoring activities, asset information as of December 31, 2013 and 2012 is included in the following tables together with financial information concerning our reportable segments for the years ended December 31, 2013, 2012 and 2011.

 

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Geographical Data

Although we own no long-term assets outside the United States, our Sand segment began selling some product in Canada during 2013. In 2013, we recognized $13.6 million of sales in Canada. All other sales have occurred in the United States.

16.   DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

We follow FASB ASC 820, which defines fair value, establishes a framework for measuring fair value, and specifies disclosures about fair value measurements. FASB ASC 820 establishes a valuation hierarchy for disclosure of the inputs to valuation used to measure fair value. This hierarchy prioritizes the inputs into three broad levels as follows.

•

Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities.



•

Level 2 inputs are quoted prices for similar assets and liabilities in active markets or inputs that are observable for the asset or liability, either directly or indirectly through market corroboration, for substantially the full term of the financial instrument.



•

Level 3 inputs are measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources.

Our valuation models consider various inputs including (a) mark to market valuations, (b) time value and, (c) credit worthiness of valuation of the underlying measurement.

A financial asset or liability's classification within the hierarchy is determined based on the lowest level of input that is significant to the fair value measurement.

The following table shows the three interest rate swap agreements we entered into during 2013 to manage interest rate risk associated with our variable rate borrowings.

As of December 31, 2012, we did not have any outstanding interest rate swaps.

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Our Fuel segment utilizes financial hedging arrangements whereby we hedge a portion of our gasoline and diesel inventory, which reduces our commodity price exposure on some of our activities. The derivative commodity instruments we utilize consist mainly of futures traded on the New York Mercantile Exchange. As of December 31, 2013 and 2012, we had 40 and 188 open commodity derivative contracts, respectively, to manage fuel price risk.

We do not designate our derivative instruments as hedges under GAAP. As a result, we recognize derivatives at fair value on the consolidated balance sheet with resulting gains and losses reflected in interest expense (for interest rate swap agreements) and cost of goods sold (for derivative commodity instruments), as reported in the consolidated statements of operations. Our derivative instruments serve the same risk management purpose whether designated as a hedge or not. We derive fair values principally from published market interest rates and fuel price quotes (Level 2 inputs). The precise level of open position commodity derivatives is dependent on inventory levels, expected inventory purchase patterns and market price trends. We do not use derivative financial instruments for trading or speculative purposes.

The fair values of outstanding derivative instruments and their classifications within our Consolidated Balance Sheets are summarized as follows:

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

17.   RETIREMENT PLAN

We sponsor 401(k) plans for substantially all employees. At December 31, 2013, we maintained legacy plans from our predecessor and the legacy plan from Direct Fuels. The plans are comparable generally in terms of employee eligibility, participation, and benefits. The plans provide for us to match 100% of the participants' contributions up to a range of 4% to 5% of the participant's pay. Additionally, we can make discretionary contributions as deemed appropriate by management. Our employer contributions to these plans totaled $0.4 million, $0.2 million, and $0.2 million for the years ended December 31, 2013, 2012, and 2011, respectively.

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18.   SUPPLEMENTAL CASH FLOW DISCLOSURES

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

19.   SUBSEQUENT EVENTS

Fourth Quarter Distribution

On January 23, 2014, the Board of Directors approved a quarterly distribution of $1.00 per common unit. We paid $23.2 million on February 14, 2014 to holders of record as of February 6, 2014. We also distributed $0.8 million to the CEO and the Sand Officer pursuant to terms of the LTIP.

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ITEM 9.            CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANT ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A.        CONTROLS AND PROCEDURES

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

We carried out an evaluation, under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer of our general partner, of the effectiveness of the design and operation of our disclosure controls and procedures as of the end of the period covered by this Report on Form 10-K pursuant to Securities Exchange Act of 1934 Rule 13a-15. Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer of our general partner concluded that, as of December 31, 2013, our disclosure controls and procedures were effective.

Management's Annual Report on Internal Control Over Financial Reporting and Attestation Report of the Registered Public Accounting Firm

This Annual Report on Form 10-K does not include management's assessment regarding internal control over financial reporting or an attestation report of our independent registered public accounting firm due to a transition period established by rules of the SEC for newly public companies. Further, our independent public accounting firm will not be required to formally attest to the effectiveness of our internal controls over financial reporting as long as we are an "emerging growth company" pursuant to the provisions of the JOBS Act.

Changes in Internal Control Over Financial Reporting

There has been no change in our internal control over financial reporting during the quarter ended December 31, 2013 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B.        OTHER INFORMATION

MSHA Violation

On July 21, 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Act") was enacted. Section 1503 of the Act included new reporting requirements related to mine safety, including disclosing on a Current Report on Form 8-K the receipt of an imminent danger order under Section 107(a) of the Federal Mine Safety and Health Act of 1977 ("the Mine Act") issued by the federal Mine Safety and Health Administration ("MSHA").

On October 21, 2013, at approximately 03:50 p.m. CST, SSS received an imminent danger order (the "Order") under Section 107(a) of the Mine Act at the Clinton Dry Plant. The Order was issued when a representative of MSHA allegedly observed a truck driver for Chippewa Valley Grain and Processing, Inc. standing on the top edge of the driver's side rear of his semi-trailer without the use of fall protection. As a fall from the 10 foot 3 inch edge to the blacktop road below could cause fatal injuries, an imminent danger order was issued to the Environmental Health and Safety Manager for SSS. The truck driver was safely removed from the area and instructed to wear fall protection in the future. No one was injured as a result of the incident and the Order was terminated approximately 30 minutes after it was issued.

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PART III

ITEM 10.        DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Partnership Management

We are managed and operated by the directors and executive officers of our general partner, Emerge Energy Partners GP LLC. Our general partner is not elected by our unitholders and will not be subject to re-election in the future. Our general partner has a board of directors, and our unitholders are not entitled to elect the directors or directly or indirectly participate in our management or operations. Our general partner owes certain fiduciary duties to our unitholders as well as a fiduciary duty to its owners. Our general partner is liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically nonrecourse to it. Whenever possible, we intend to incur indebtedness that is nonrecourse to our general partner.

Our general partner's board of directors has seven directors, three of whom are independent as defined under the independence standards established by the NYSE and the Exchange Act. Our general partner's board of directors has affirmatively determined that Messrs. Clark, Kelly, and McCarthy are independent as described in the rules of the NYSE and the Exchange Act. The NYSE does not require a listed publicly traded partnership, such as ours, to have a majority of independent directors on the board of directors of our general partner or to establish a compensation committee or a nominating committee.

Directors and Executive Officers

Directors are appointed for a term of one year and hold office until their successors have been elected or qualified or until the earlier of their death, resignation, removal or disqualification. Officers serve at the discretion of the board. The following table shows information for the directors and executive officers of our general partner.

Ted W. Beneski

Ted W. Beneski was elected Chairman of the Board and appointed as a member of the board of directors of our general partner in April 2012. Since May 2002, Mr. Beneski has served as the Chief Executive Officer and Managing Partner of Insight Equity Holdings LLC. Mr. Beneski also serves as Chairman of the Board of Direct Fuels and SSS, positions he has held since May 2003 and June 2008, respectively. Prior to founding Insight Equity, Mr. Beneski was a founding principal of the Carlyle Management Group, a private equity group specializing in investments in turnarounds and special situation investment opportunities, and served as Senior Vice President from January 2000 to May 2002. Mr. Beneski was also co-founder of the Dallas office of Bain & Company, or Bain, a global leader in strategy-based management consulting services, and served as a Senior Partner and Managing Director. His tenure at Bain (both in Boston and Dallas) was from September 1985 to December 1999. While at Bain, Mr. Beneski advised Fortune 100 clients across a wide range of industries in the areas of portfolio and business unit strategy,

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mergers and acquisitions, operational improvement, organizational and process redesign, new product introduction and growth strategy. Prior to his time at Bain, Mr. Beneski worked for five years as a commercial banker with Bankers Trust in New York and Shawmut Corporation in Boston.

Mr. Beneski also serves as Chairman of the Board at the following Insight Equity portfolio companies: Vision-Ease Lens, Hirschfeld Industries, Walker Group Holdings, Aviation Investment Holdings, Atwood Mobile Products, Meadow Valley, The Berry Family of Nurseries, Versatile Processing Group, Inc. and A.P. Plasman. Mr. Beneski received his MBA from Harvard Business School and a BA from Amherst College, majoring in economics. Mr. Beneski was selected to serve on the board of directors of our general partner due to his affiliation with Insight Equity, his knowledge of the industries in which we operate and his financial and business expertise.

Rick Shearer

Rick Shearer was elected Chief Executive Officer of our general partner in April 2012. Since May 2010, Mr. Shearer has served as President and Chief Executive Officer of SSS. Mr. Shearer previously served from March 2007 to May 2010 as President and Chief Executive Officer of Black Bull Resources, a company that specializes in the mining, processing and marketing of industrial minerals that is publicly traded on the TSX Venture Exchange. Mr. Shearer currently serves as the Chairman of the Board of Black Bull Resources. From January 2004 to March 2007, Mr. Shearer served as a member of the board of directors of Excell Minerals, a global stainless steel metals recovery company based in Pittsburgh, Pennsylvania, prior to its acquisition by Harsco Corporation in February 2007. Mr. Shearer also previously served as the President and Chief Operating Officer of U.S. Silica Company Inc., a silica sand supplier, from August 1997 to January 2004.

Mr. Shearer served as Founding Chairman of the Industrial Minerals Association of North America, as Vice Chairman of the National Industrial Sand Association and as a Board Member of the Industrial Minerals Association of Europe from 2003 to 2004. Mr. Shearer has a Bachelor of Science degree from Alderson-Broaddus College and a Masters of Business Administration degree from Eastern Michigan University. He is also a graduate of the Executive Management Program at Harvard University.

Warren B. Bonham

Warren B. Bonham was elected Vice President and appointed as a member of the board of directors of our general partner in April 2012 and currently manages the operations of our Fuel segment. Since February 2012, Mr. Bonham has been a Partner of Insight Equity Holdings LLC. Additionally, he has served as President and Chief Executive Officer of Direct Fuels since January 2008 and previously served as President from June 2006 to December 2007. Mr. Bonham also previously served as Vice President of Hirschfeld Steel, a company that specializes in the fabrication of structural steel components for construction projects such as bridges, industrial and nuclear facilities, mass transit systems, and stadiums, from September 2010 to January 2012 and from June 2006 to December 2007. From August 2002 to May 2006, Mr. Bonham served as the Chief Financial Officer of GES Exposition Services, the largest subsidiary of Viad Corporation, a publicly traded exhibition and event services company. Prior to joining GES Exposition Services, Mr. Bonham served as Chief Financial Officer of Electrolux LLC, a private equity owned direct seller of floor care equipment, from August 1998 to July 2002. From 1995 to 1998, Mr. Bonham worked as a Senior Manager at Bain, where he worked on operational improvement cases in many different industries on three different continents.

Mr. Bonham serves on the board of directors at a number of Insight Equity's portfolio companies including AEC Holdings and SSH. Mr. Bonham received his MBA from Harvard Business School and his Bachelor of Commerce degree from Queen's University where he graduated first in his class. He is also a licensed Chartered Accountant. Mr. Bonham was selected to serve on the board of directors of our general partner

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due to his affiliation with Insight Equity, his knowledge of the industries in which we operate and his financial and business expertise.

Robert Lane

Robert Lane was appointed Chief Financial Officer of our general partner in November 2012. From December 2011 until his appointment as our Chief Financial Officer, Mr. Lane was a Managing Director at Global Hunter Securities LLC, where he was responsible for the origination and execution of capital markets and M&A transactions in the midstream industry. Mr. Lane previously served in various roles as Vice President, Senior Vice President and eventually Managing Director of Sander Morris Harris Inc. and its affiliates from November 2004 to December 2011, where he led equity research and then investment banking coverage of midstream energy companies, particularly master limited partnerships. From 2003 to 2004, Mr. Lane served as Director of Finance and Accounting and later Chief Financial Officer of Unico Corporation, a company which provided industrial and commercial uniforms to the utility, petrochemical, general industry, and corporate identity markets. Prior to joining Unico Corporation, Mr. Lane served as an independent consultant for startup companies in the Houston area from 2002 to 2003. From 1998 to 2003, Mr. Lane worked as a Senior Associate and later as a Vice President for Vulcan Capital Management, Inc., and from 1994 to 1997, Mr. Lane served as a Senior Analyst for Smith Barney Inc.

Mr. Lane is a Certified Public Accountant and a Chartered Financial Analyst. Mr. Lane received his MBA from the University of Pennsylvania's Wharton School and his Bachelor of Arts degree from Princeton University. He also received a Certificate in the Accountancy Program from the B.T. Bauer School of Business at the University of Houston.

Kevin Clark

Kevin Clark has served as a member of our board of directors since March 2013. Since January 2002 he has taught classes in corporate strategy and accounting at Vanderbilt University as an Adjunct Professor, a Senior Lecturer and, since August 2010, as an Associate Professor. Prior to joining the faculty at Vanderbilt, Mr. Clark was a partner at Executive Perspectives Inc., an executive education firm focused on strategy, finance and team building, from October 1985 to November 1998. He is the co-managing partner of RG Clark Family Holdings, LLC, serving in that role since November 2011, and also serving as Secretary and Treasurer from September 2000 to the present. He has also served as a Director for Sullivan Street Development, Inc., a small private corporation, since June 2001.

Mr. Clark holds a B.S. in physics from Amherst College and an M.S. in computer and information science from Dartmouth College. Mr. Clark was chosen to serve on the board of our general partner due to his expertise in corporate strategy and accounting.

Francis J. Kelly, III

Francis J. Kelly, III was appointed as an independent director of our general partner in March 2013. Mr. Kelly is President and CEO of CEOVIEW Branding LLC, a brand strategy consulting firm. Prior to forming CEOVIEW, Mr. Kelly was with Arnold Worldwide, LLC, a large advertising agency. Mr. Kelly joined Arnold Worldwide in January 1994 as Chief Marketing officer, and advanced to become President in 2002, CEO in 2006, and eventually Vice Chairman in 2010 until his resignation in 2014. Mr. Kelly has led a number of successful branding strategies for public and private companies while helping Arnold Worldwide shape its strategic and creative philosophy. From 1989 to 1994, Mr. Kelly worked at Leonard Monahan and Lubars, an advertising agency subsequently renamed Leonard Monahan Lubars and Kelly. From 1983 to 1988, Mr. Kelly developed integrated campaigns for national brands while working for Humphrey Browning MacDougall. His career in the field of branding, advertising, and integrated marketing communications also includes time at Young & Rubicam New York.

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Mr. Kelly received his MBA from Harvard Business School and his Bachelor of Arts degree from Amherst College. He also serves on the boards of the Boston Chamber of Commerce and the Friends of the Boston Public Library. Mr. Kelly was selected to serve on the board of directors of our general partner due to his marketing, financial and business expertise.

Kevin McCarthy

Kevin McCarthy was appointed as an independent director of our general partner in July 2012. Mr. McCarthy is Chairman, Chief Executive Officer and President of Kayne Anderson MLP Investment Company, Kayne Anderson Energy Total Return Fund, Inc., Kayne Anderson Midstream/Energy Fund, Inc. and Kayne Anderson Energy Development Company, which are each NYSE listed closed-end investment companies. Mr. McCarthy joined Kayne Anderson Capital Advisors as a Senior Managing Director in 2004 from UBS Securities LLC, where he was global head of energy investment banking. In this role, he had senior responsibility for all of UBS's energy investment banking activities, including direct responsibilities for securities underwriting and mergers and acquisitions in the energy industry. From 1995 to 2000, Mr. McCarthy led the energy investment banking activities of Dean Witter Reynolds and then PaineWebber Incorporated. He began his investment banking career in 1984. He is also on the board of directors of Range Resources Corporation (a publicly traded natural gas exploration and production company) and ProPetro Services, Inc. (a private oilfield services company). He earned a Bachelor of Arts in Economics and Geology from Amherst College and an MBA in Finance from the University of Pennsylvania's Wharton School. Mr. McCarthy was selected to serve on the board of directors of our general partner due to his knowledge of the industries in which we operate and his financial and business expertise.

Eliot E. Kerlin, Jr.

Eliot E. Kerlin Jr. was appointed as a member of the board of directors of our general partner in March 2013. Mr. Kerlin is a Partner at Insight Equity Holdings LLC and has been a member of the firm since July 2005. During his time at Insight Equity Holdings LLC, Mr. Kerlin has led a number of acquisitions, recapitalizations, financings, and operational improvement initiatives at portfolio companies. During 2004, Mr. Kerlin served as a turnaround manager for Bay State Paper Company, a containerboard and craft paper manufacturer. From 2000 to 2003, Mr. Kerlin worked as a Senior Associate at Jupiter Partners, a middle market private equity fund. He began his career as an investment banker at Merrill Lynch Pierce Fenner & Smith.

Mr. Kerlin currently serves as an Executive Vice President and board member for a number of Insight Equity's portfolio companies, including SSS. He received his MBA from Harvard Business School and his Bachelor of Business Administration degree in finance from Texas A&M University. Mr. Kerlin also serves on several non-profit, community and professional boards of directors. Mr. Kerlin was selected to serve on the board of directors of our general partner due to his affiliation with Insight Equity, his knowledge of the industries in which we operate and his financial and business expertise.

Victor L. Vescovo

Victor L. Vescovo was appointed as a member of the board of directors of our general partner in April 2012. Since January 2003, Mr. Vescovo has served as the Chief Operating Officer and Managing Partner of Insight Equity Holdings LLC, which he co-founded with Mr. Beneski. From 1999 to 2001, Mr. Vescovo was Vice President of Product Development of Military Advantage, a venture-backed company sold to Monster Worldwide, Inc. in 2004. From 1994 to 1999, he was a Senior Manager at Bain where he focused on merger integration and operational improvement cases. Mr. Vescovo previously worked in the mergers & acquisitions department of Lehman Brothers Holdings Inc. where he was responsible for company due diligence and transaction execution, as well as working overseas in the Middle East advising the Saudi government on business investments from 1991 to 1992.

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Mr. Vescovo also serves as a Managing Director and board member of all of Insight Equity's portfolio companies, including AEC Holdings and SSH. Additionally, Mr. Vescovo served 21 years in the U.S. Navy (Reserve) with specialties in operational targeting and counter-terrorism and retired in the fall of 2013 with the rank of Commander (O-5). Mr. Vescovo received his MBA from the Harvard Business School. He also received a Master's Degree from the Massachusetts Institute of Technology and earned a double major Bachelor of Arts in economics and political science from Stanford University. Mr. Vescovo was selected to serve on the board of directors of our general partner due to his affiliation with Insight Equity, his knowledge of the industries in which we operate and his financial and business expertise.

Corporate Governance

The board of directors of our general partner has adopted corporate governance guidelines to assist it in the exercise of its responsibilities to provide effective governance over our affairs for the benefit of our unitholders. In addition, we have adopted a code of business conduct and ethics, which sets forth legal and ethical standards of conduct for all our officers, directors and employees. The corporate governance guidelines, the code of business conduct and ethics and the charters of our audit and conflicts committees are available on our website at www.emergelp.com and in print without charge to any unitholder who requests any of them. A unitholder may make such a request in writing by mailing such request to Robert Lane at Investor Relations, Emerge Energy Services LP, 180 State Street, Suite 225, Southlake, Texas 76092. Amendments to, or waivers from, the code of business conduct and ethics will also be available on our website and reported as may be required under SEC rules; however, any technical, administrative or other non-substantive amendments to the code of business conduct and ethics may not be posted. Please note that the preceding Internet address is for information purposes only and is not intended to be a hyperlink. Accordingly, no information found or provided at that Internet address or at our website in general is intended or deemed to be incorporated by reference herein.

Conflicts Committee

Our partnership agreement provides for the Conflicts Committee, as circumstances warrant, to review conflicts of interest between us and our general partner or between us and affiliates of our general partner. The Conflicts Committee, consisting solely of independent directors, determines if the resolution of a conflict of interest that has been presented to it by our general partner is fair and reasonable to us. The members of the Conflicts Committee may not be executive officers or employees of our general partner or directors, executive officers or employees of its affiliates. In addition, the members of the Conflicts Committee must meet the independence and experience standards established by the NYSE and the Exchange Act. Messrs. Clark and Kelly serve as the members of the Conflicts Committee. Mr. Kelly serves as the chair of our Conflicts Committee.

Audit Committee

The board of directors of our general partner has established an audit committee, or Audit Committee, that complies with the NYSE requirements and Section 3(a)(58)(A) of the Exchange Act. Our general partner is generally required to have at least three independent directors serving on its board at all times. Messrs. Clark and Kelly are our independent directors and serve as the members of the Audit Committee. The board has determined that Mr. Clark, who serves as the chairman of the Audit Committee, and also Mr. Kelly, each have such accounting or related financial management expertise sufficient to qualify him as an audit committee financial expert in accordance with Item 401 of Regulation S-K.

The Audit Committee meets on a regularly scheduled basis with our independent accountants at least four times each year and is available to meet upon the request of any committee member. The Audit Committee has the authority and responsibility to review our external financial reporting, to review our procedures for internal auditing and the adequacy of our internal accounting controls, to consider the qualifications and independence of our independent accountants, to engage and resolve disputes with our

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independent accountants, including the letter of engagement and statement of fees relating to the scope of the annual audit work and special audit work that may be recommended or required by the independent accountants, and to engage the services of any other advisors and accountants as the Audit Committee deems advisable. The Audit Committee reviews and discusses the audited financial statements with management, discusses with our independent auditors matters required to be discussed by Public Company Accounting Oversight Board Auditing Standard No. 16 (Communications with Audit Committees) and Rule 3520 (Auditor Independence), and makes recommendations to the board of directors of our general partner regarding the inclusion of our audited financial statements in this Annual Report on Form 10-K.

The Audit Committee is authorized to recommend periodically to the board of directors any changes or modifications to its charter that the Audit Committee believes may be required or desirable.

Communication with the Board of Directors

A holder of our units or other interested party who wishes to communicate with the non-management directors or independent directors of our general partner may do so by contacting our corporate secretary at the address or phone number appearing on the front page of this Report. Communications will be relayed to the intended recipient of the Board except in instances where it is deemed unnecessary or inappropriate to do so. Any communications withheld will nonetheless be recorded and available for any director who wishes to review them.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Exchange Act requires our general partner's board of directors and executive officers, and persons who own more than 10 percent of a registered class of our equity securities, to file with the SEC and any exchange or other system on which such securities are traded or quoted initial reports of ownership and reports of changes in ownership of our common units and other equity securities. Officers, directors and greater than 10 percent unitholders are required by the SEC's regulations to furnish to us and any exchange or other system on which such securities are traded or quoted with copies of all Section 16(a) forms they filed with the SEC. To our knowledge, based solely on a review of the copies of such reports furnished to us and written representations that no other reports were required, we believe that all reporting obligations of our general partner's officers, directors and greater than 10 percent unitholders under Section 16(a) were satisfied during the year ended December 31, 2013. Due to administrative oversight, the Forms 3 filed by Insight Equity Management Co. LLC and by Messrs. Beneski, Vescovo, Shearer, Lane, Bonham, McCarthy, Kelly, Clark and Kerlin in connection with their appointment to the board of directors of our general partner were not timely filed. On May 16, 2013, a Form 3 was filed as to Insight Equity Management Co. LLC and each of the directors and officers stating the amount of our securities owned by each of them on May 8, 2013, which is the date that they became insiders in connection with of our initial public offering. In addition, due to administrative oversight, the Form 3 filed by Mr. DeShazo in connection with his appointment as Chief Accounting Officer of our general partner was not timely filed. A Form 3 was filed on June 1, 2013 stating the amount of our securities owned by Mr. DeShazo as of May 29, 2013, the date which he was appointed to his position. A Form 4 with respect to the securities acquired by Mr. Kerlin in connection with the closing of our initial public offering was not timely filed due to administrative oversight. A Form 4 was filed on October 2, 2013 stating the securities he acquired as of as of May 14, 2013.

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ITEM 11.        COMPENSATION DISCUSSION AND ANALYSIS

We are an "emerging growth company" as defined under the Jumpstart Our Business Startups (JOBS) Act. As such, we are permitted to meet the disclosure requirements of Item 402 of Regulation S-K by providing the reduced disclosures required of a smaller reporting company.

This section describes the material components of the executive compensation program for our executive officers who are named in the "Summary Compensation Table" below. Our named executive officers and their positions for the year ended December 31, 2013 consisted of the following three individuals:

•

Rick Shearer, President and Chief Executive Officer of Emerge Energy Services GP LLC, our general partner;



•

Warren Bonham, Vice President of our general partner; and



•

Robert Lane, Chief Financial Officer of our general partner.

Summary Compensation Table

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Narrative Disclosure to Summary Compensation Table

Employment Letters

Our general partner is a party to employment letters with Messrs. Shearer and Lane, each of which is described below. We have not entered into an employment letter or employment agreement with Mr. Bonham.

Rick Shearer.    Our general partner and Mr. Shearer are parties to an amended employment letter agreement (the "Amended Shearer Letter"), dated May 29, 2013 that provides for Mr. Shearer's employment as Chief Executive Officer of our general partner. The Amended Shearer Letter amends and restates the employment letter agreement between SSS and Mr. Shearer, dated March 23, 2010 and amended May 17, 2011, which was assigned to our general partner in connection with our IPO. The Amended Shearer Letter expires on December 31, 2015, unless earlier terminated, and the term of the Amended Shearer Letter is subject to automatic one-year renewals unless either our general partner or Mr. Shearer gives written notice of termination at least 60 days prior to the end of the applicable term.

Under the Amended Shearer Letter, Mr. Shearer's annual base salary is $360,000, which is subject to automatic annual increases of at least four percent, and Mr. Shearer is eligible to receive an annual discretionary cash performance bonus under any general partner bonus plan or program applicable to similarly-situated employees. The Amended Shearer Letter also provides that Mr. Shearer is eligible to participate in the welfare benefit plans maintained by our general partner on the same basis as similarly-situated employees, and is entitled to annual physical examinations, paid by our general partner, in an amount up to $3,000 per year.

Robert Lane.    In October 2012, we entered into an employment letter with Robert Lane pursuant to which Mr. Lane currently serves as Chief Financial Officer of our general partner. We assigned this employment agreement to our general partner in connection with our IPO. On May 29, 2013 our general partner amended the employment letter (as amended, the "Amended Lane Letter"). Under the Amended Lane Letter, Mr. Lane's annual base salary is $256,000 and he is eligible to receive an annual cash bonus, targeted at 50% of his annual base salary, based on the achievement of applicable company performance targets. In addition, pursuant to the Amended Lane Letter, Mr. Lane received a signing bonus totaling $50,000, half of which was paid in November 2012 and half of which was paid in March 2013. Mr. Lane is also entitled to participate in the health and welfare benefit plans maintained by our general partner from time to time. The Amended Lane Letter provides that Mr. Lane is eligible to participate in two long-term incentive compensation programs, as described under "— Long-Term Incentive Compensation Programs" below.

The Amended Shearer Letter and the Amended Lane Letter also provide for certain payments and benefits upon a termination of employment by our general partner without "cause" (as defined in the applicable employment letter), as described under "—Severance and Change in Control Benefits" below.

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2013 Base Salary

The named executive officers receive a base salary to compensate them for services rendered to our company. The base salary payable to each named executive officer is intended to provide a fixed component of compensation reflecting the executive's skill set, experience, role and responsibilities.

Base salaries for the named executive officers are reviewed periodically by the board of directors of our general partner, and adjustments are made generally in accordance with the considerations described above and to maintain base salaries at competitive levels. These periodic reviews consider, among other things, general economic conditions, industry specific business conditions, base salaries for comparable positions in similar industries, the tenure of the officers, and base salaries of the officers relative to one another. In recognition of increased responsibilities and duties resulting from our recent IPO, in January 2014 the board of directors of our general partner increased the base salaries of Messrs. Shearer, Bonham and Lane to $425,000, $200,000 and $266,240, respectively.

2013 Annual Performance-Based Compensation and Discretionary Bonuses

For 2013, Mr. Shearer was eligible to receive an annual incentive bonus based on the achievement by SSS of pre-established adjusted EBITDA targets. Achievement of adjusted EBITDA at the threshold level would result in a bonus payment equal to 45% of Mr. Shearer's base salary, and achievement beyond the threshold level would result in an increased bonus payout percentage, determined by straight-line interpolation. Based on the 2013 adjusted EBITDA achieved by SSS, Mr. Shearer was awarded a cash bonus equal to 122% of Mr. Shearer's base salary, or $382,768. For purposes of the bonus program, "Adjusted EBITDA" is defined as SSS net income plus interest expense, tax expense, depreciation, depletion and amortization expense, non-cash charges and unusual or non-recurring charges less interest income, tax benefits and selected gains that are unusual or non-recurring, net of any bonus accrual.

For 2013, Mr. Bonham was eligible to receive a discretionary incentive bonus, and Mr. Lane was eligible to receive a discretionary incentive bonus with a target payout of 50% of his salary, with the actual amounts to be determined at the discretion of our general partner. Based on our overall financial performance in 2013, the board of directors of our general partner awarded Mr. Bonham a $200,000 discretionary bonus and awarded Mr. Lane a $128,000 discretionary bonus.

In 2013, we also awarded Mr. Bonham a one-time discretionary bonus of $930,080 in connection with the completion of our IPO and we awarded Mr. Lane the remaining $25,000 of his signing bonus.

Long-Term Incentive Compensation Programs

Rick Shearer.    In 2013, Mr. Shearer participated in a long-term incentive compensation program maintained by SSS, referred to as the Shearer LTIC, pursuant to which Mr. Shearer was eligible to receive a cash bonus based on "net cash proceeds" received in connection with an "ultimate sale transaction" of SSS (each, as defined in the LTIC). Under the Shearer LTIC, in the event of an ultimate sale transaction, Mr. Shearer was eligible to receive up to 5.30% of the net cash proceeds received in such transaction in excess of $25,000,000. Mr. Shearer vested as to 50% of his right to receive any such payment on each of May 1, 2012 and May 1, 2013. In connection with our IPO, our general partner terminated the Shearer LTIC and in connection therewith, agreed to pay to Mr. Shearer an amount equal to $4,270,731, payable within ten days following May 29, 2014. Mr. Shearer does not currently participate in any cash-based long-term incentive compensation program.

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Robert Lane.    The Lane Letter Agreement provides that Mr. Lane is eligible to participate in two cash-based long-term incentive compensation programs.

Under the first program (the "Distribution LTIC"), Mr. Lane is eligible to receive a cash bonus of up to $100,000 for each of 2013, 2014 and 2015 (pro-rated in 2013 to reflect the partial year following our initial public offering) based on the amount by which our regular annual distribution exceeds $58,049,200. Under the second program (the "Unit Price LTIC"), Mr. Lane is eligible to receive a cash bonus of up to $125,000 for each of 2013, 2014 and 2015 (pro-rated in 2013 to reflect the partial year following our IPO) based on the amount by which the average daily trading value of our common units for the applicable year exceeds the per unit equity value of our common units upon the completion of our IPO. Each of the Distribution LTIC and the Unit Price LTIC are calculated on an annual basis and are payable in a cash lump sum after December 31, 2015 (but no later than March 15, 2016), subject to Mr. Lane's continuous employment through December 31, 2015. Based on our performance in 2013, Mr. Lane earned $64,932 and $81,164 under the Distribution LTIC and the Unit Price LTIC, respectively, with respect to 2013 performance. These amounts are not illustrated in the Summary Compensation table, as they were earned in 2013 but are not yet vested.

Warren Bonham.    Mr. Bonham does not currently participate in any cash-based long-term incentive compensation program.

Equity Compensation

Pursuant to our 2013 Long-Term Incentive Plan, which we adopted in connection with our IPO, in 2013 we made grants of phantom units to certain of our executive officers and other employees, including Messrs. Shearer and Bonham. Each phantom unit award was denominated as a specified dollar value, and the actual number of units awarded was calculated by dividing the total denominated dollar value of the award by the per unit IPO price of our common units. The number of phantom units granted to our named executive officers in connection with our IPO is set forth in the table below:

The phantom units awarded to Mr. Shearer in connection with our IPO are subject to time-based vesting in annual installments over a period of two years commencing on the date of grant (May 14, 2013), subject to his continued service. In addition, Mr. Shearer's phantom unit award will accelerate and vest in full immediately prior to a change in control or upon a termination of service without "cause," for "good reason" (each, as defined in the applicable award agreement) or due to Mr. Shearer's death or disability. Mr. Shearer's phantom units were accompanied by tandem distribution equivalent rights ("DERs"). DERs are rights to receive an amount equal to all or a portion of the cash distributions made on units during the period a phantom unit remains outstanding. In the case of Mr. Shearer, his DERs were vested as of the date of grant (May 14, 2013). In 2013, we distributed $652,623 to Mr. Shearer related to his DERs.

The phantom units awarded to Mr. Bonham in connection with our IPO will vest, subject to his continued service, in pro-rated installments in connection with the sale or disposition of common units held by Insight Equity based on the ratio of common units sold or disposed of by Insight Equity as compared to the total number of common units held by Insight Equity immediately following the completion of our IPO, and will accelerate and vest in full immediately prior to a change in control. In the case of Mr. Bonham, DERs vest when the associated phantom units vest. In 2013, the DERs associated with Mr. Bonham's phantom unit award accrued $148,323 of distributions.

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Mr. Lane was not granted an equity award in 2013.

Employee Benefits and Perquisites

Our full-time employees, including the named executive officers, are eligible to participate in our health and welfare plans, including:

•

medical and dental benefits;



•

short-term and long-term disability insurance;



•

accidental death and dismemberment insurance; and



•

life insurance.

The employee benefits programs are designed to be affordable and competitive in relation to the market, and may be modified as needed based upon regular monitoring of applicable laws and practices in the competitive market. These benefits are provided to the named executive officers on the same general terms as they are provided to all of our full-time employees. In addition, Mr. Shearer is entitled to receive company-paid annual physical exams, not to exceed $3,000 per year, which are supplemental to the health benefits provided to employees of our general partner generally. Until May 2013, Mr. Shearer received a $400 monthly auto allowance.

Through its subsidiaries, our general partner maintains a 401(k) retirement savings plans for its employees, including Mr. Shearer and Mr. Lane, who satisfy certain eligibility requirements. The Internal Revenue Code of 1986, as amended, allows eligible employees to defer a portion of their compensation, within prescribed limits, on a pre-tax basis through contributions to the 401(k) plan. We believe that providing a vehicle for tax-deferred retirement savings though a 401(k) plan, and making fully vested matching contributions, adds to the overall desirability of our executive compensation package and further incentivizes our employees, including the named executive officers, in accordance with our compensation policies.

In the future, we may provide perquisites or other personal benefits in limited circumstances, such as where we believe it is appropriate to assist an individual named executive officer in the performance of his duties, to make our named executive officers more efficient and effective, and for recruitment, motivation and/or retention purposes. Future practices with respect to perquisites or other personal benefits for our named executive officers will be approved and subject to periodic review by the board of directors of our general partner.

Outstanding Equity Awards at December 31, 2013

The following table summarizes the number of shares of our common units underlying outstanding equity incentive plan awards for each named executive officer as of December 31, 2013:

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Severance and Change in Control Benefits

The Amended Shearer Letter provides that if Mr. Shearer's employment is terminated by our general partner without "cause" (as defined in the Amended Shearer Letter) during (a) the first thirty-six months after his hire date or (b) during any subsequent one-year extension (which occurs automatically unless either party provides notice at least 30 days prior to the end of the initial three-year period or subsequent one-year extension), Mr. Shearer will be entitled to receive an amount equal to twice his then-current annual base salary, payable as a lump sum within sixty days after the termination date.

The Amended Lane Letter provides that if Mr. Lane's employment is terminated by the Company without "cause" (as defined in the Amended Lane Letter), then Mr. Lane will be entitled to receive (a) an amount equal to his annual base salary (or, if such termination occurs within two months following a "change in control" (as defined in the Amended Lane Letter), an amount equal to 27 months' of his annual base salary) and (b) immediate vesting in, and payment of, the Distribution LTIC and Unit Price LTIC to the extent each has been earned as of the termination date, with any partial years calculated on quarterly basis through the end of the fiscal quarter immediately preceding the termination date. Each of the payments described in this paragraph will be paid in a cash lump sum on the 60th day following Mr. Lane's termination date, subject to his timely execution and non-revocation of a release of claims.

Except with respect to his phantom unit award, Mr. Bonham is not eligible to receive any severance or change in control benefits.

Director Compensation

On May 14, 2013, the board of directors of our general partner adopted the Emerge Energy Services LP Director Compensation Program (the "Director Plan"). Any non-employee director not affiliated with the partnership, our general partner, or certain Insight Equity affiliates is eligible to receive awards under the Director Plan.

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Cash Compensation

Under the Director Plan, each eligible director is entitled to receive an annual cash retainer of $50,000. In addition, each committee chairperson receives a $10,000 annual cash retainer and each non-chair committee member receives a $2,500 annual cash retainer. Annual retainers are paid in cash quarterly in arrears and are paid effective as of the first day of the calendar quarter in which our IPO occurred. Other than with respect to the calendar quarter in which our IPO occurred, annual retainers are pro-rated to reflect any partial year of service.

Equity Compensation

Under the Director Plan, each eligible director serving on the board of directors at the time of our IPO was granted 3,529 restricted units on the date of the closing of our IPO. These awards will vest in full on the first anniversary of the grant date (May 14, 2014), subject to continued service.

In addition, under the Director Plan, any other eligible director who joins the board of directors of our general partner will receive a grant of restricted units covering a number of units having a value equal to $60,000 when he or she joins the board of directors of our general partner, pro-rated to reflect any partial year of service. Each restricted unit grant will vest in full on the anniversary of the closing of our IPO (May 14, 2014) immediately following the applicable grant date, subject to the eligible director's continued service through the applicable vesting date. An eligible director serving on the board of directors of our general partner as of an anniversary of the closing of our IPO will be granted a restricted unit award valued at $60,000 on the applicable anniversary date, which will vest in full on the first anniversary of the grant date subject to continued service through the applicable vesting date.

2013 Director Compensation Table

(1)

Only non-employee directors who are not affiliated with us, our general partner or certain Insight Equity affiliates are eligible to receive cash and/or equity compensation pursuant to the Director Plan.

(2)

The amounts shown in this column include the portion of the annual retainer and any individual retainers for serving as the chair or non-chair committee member, in each case earned in 2013.

(3)

The amounts shown in this column reflect the aggregate grant date fair value of restricted units awards granted in 2013, calculated in accordance with financial accounting standards. For a discussion of the assumptions used to calculate the value of all restricted unit awards made to directors, refer to Note 11 to our financial statements included in this Annual Report on Form 10-K for the period ended December 31, 2013. The total number of restricted units outstanding as of the end of the 2013 fiscal year for each non-employee director was 3,529.

Compensation Committee Report

As our general partner does not have a compensation committee, the board of directors of our general partner provides the oversight, administers and makes decisions regarding our compensation policies and plans. Additionally, the board of directors of our general partner generally reviews and discusses the Compensation Discussion and Analysis with senior management of our general partner as a part of our governance practices. Based on this review and discussion, the board of directors of our general partner

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has directed that the Compensation Discussion and Analysis be included in this report for filing with the SEC.

Compensation Committee Interlocks and Insider Participation

As previously discussed, the Board is not required to maintain, and does not maintain a compensation committee.

Mr. Beneski, who serves as the Chairman of the Board participates in his capacity as a director in the deliberations of the Board concerning executive officer compensation. In addition, Mr. Beneski makes recommendations to the Board regarding named executive officer compensation but abstains from any decision regarding his own compensation.

ITEM 12.        SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS

The following table sets forth certain information regarding the beneficial ownership of units as of March 17, 2014 (the "Ownership Reference Date") by:

•

each person who is known to us to beneficially own 5% or more of such units to be outstanding;



•

our general partner;



•

each of the directors and named executive officers of our general partner; and



•

all of the directors and executive officers of our general partner as a group.

All information with respect to beneficial ownership has been furnished by the respective directors, officers or 5% or more unitholders as the case may be.

The amounts and percentage of units beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a "beneficial owner" of a security if that person has or shares "voting power," which includes the power to vote or to direct the voting of such security, or "investment power," which includes the power to dispose of or to direct the disposition of such security. In computing the number of common units beneficially owned by a person and the percentage ownership of that person, common units subject to options or warrants held by that person that are currently exercisable or exercisable within 60 days of the Ownership Reference Date, if any, are deemed outstanding, but are not deemed outstanding for computing the percentage ownership of any other person. Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all units shown as beneficially owned by them, subject to community property laws where applicable.

The percentage of units beneficially owned is based on a total 23,628,208 common units outstanding as of the Ownership Reference Date. Except as indicated by footnote, the persons named in the table below

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have sole voting and investment power with respect to all units shown as beneficially owned by them and their address is 180 State Street, Suite 225, Southlake, Texas 76092.

An asterisk indicates that the person or entity owns less than one percent.

(1)

As described elsewhere in this prospectus, Ted W. Beneski and Victor L. Vescovo are the controlling equity owners of Insight Equity, which owns a controlling interest in Emerge Holdings, the entity which owns Emerge Energy Services GP, LLC. Messrs. Beneski and Vescovo, by virtue of being controlling equity owners of Insight Equity, may be deemed to beneficially own the units held by Insight Equity. Messrs. Beneski and Vescovo disclaim beneficial ownership of the units held by Insight Equity except to the extent of their pecuniary interest therein.

(2)

Amounts do not include 40,000 units for which Mr. Beneski disclaims beneficial ownership, which are held in irrevocable trust accounts in favor of his sons. Mr. Beneski is the trustee of each trust account.

(3)

Includes 265,294 unvested phantom units granted to our Chief Executive Officer. Such phantom units are deemed beneficially owned because they will vest on May 14, 2014, the one year anniversary of our initial public offering, which is less than 60 days from the Ownership Reference Date.

(4)

Represents unvested restricted units granted to our independent directors. Such units are deemed beneficially owned because the units will vest on May 14, 2014, the one year anniversary of our initial public offering, which is less than 60 days from the Ownership Reference Date.

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Securities Authorized for Issuance under Equity Compensation Plans

The following table summarizes certain information regarding our equity compensation plans, including our LTIP, as of December 31, 2013. Our LTIP allows for awards of options, phantom units, restricted units, unit awards, other unit awards and unit appreciation rights.

(1)

The amounts in column (a) of this table reflect only phantom units that have been granted (but not yet issued) under the LTIP. No unit options have been granted. Our LTIP was approved by our partners (general and limited) prior to our IPO. No value is shown in column (b) of the table, since the phantom units do not have an exercise, or strike, price.

(2)

The LTIP was adopted by the Emerge Energy Services GP LLC Board of Directors in connection with the closing of our IPO in May 2013, and provides for awards of options, restricted units, phantom units, distribution equivalent rights, substitute awards, unit appreciation rights, unit awards, profits interest units and other unit-based awards to be available for employees, consultants and directors of our general partner and any affiliates who perform services for Emerge Energy Services LP.

ITEM 13.        CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

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

Insight Equity owns 10,416,341 common units representing a 44.1% limited partner interest in us, and is controlled by Ted Beneski and Victor Vescovo, the Chairman of the Board and each a member of our board of directors. Emerge Energy Services Holdings LLC is the sole member of our general partner. Emerge Energy Services Holdings LLC is controlled by Insight Equity and Ted Beneski.

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Distributions and Payments to Our General Partner and Its Affiliates

The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with our ongoing operation and liquidation. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm's-length negotiations.

Other Agreements with Affiliates

We have various agreements with certain of our affiliates, as described below. These agreements have been negotiated among affiliated parties and, consequently, are not the result of arm's-length negotiations.

We entered into an administrative services agreement with Insight Management Company LLC pursuant to which Insight Management Company LLC provides specified general and administrative services to us and our subsidiaries from time to time. Under the terms of the agreement, we reimburse Insight Management Company LLC based on agreed upon-formulas on a monthly basis for the time and materials actually spent in performing general and administrative services on our behalf. In addition, Warren B. Bonham is considered to be an employee of Insight Management Company LLC and also serves as the head of our Fuel segment. We reimburse Insight Management Company LLC for an allocation of Mr. Bonham's time and expenses incurred in providing services to us. We expect that this administrative services agreement will remain in force until (i) the date we and Insight Management Company LLC mutually agree to terminate it; (ii) the final distribution in liquidation of us or our subsidiaries; or (iii) the date on which neither Insight Equity nor any of its affiliates own equity securities of us. We believe that the terms of the administrative services agreement are no less favorable to us than those generally available

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from unrelated third parties. We reimbursed Insight Management Company LLC $2.0 million for such services in 2013.

On September 7, 2012, SSS and SSH entered into a first lien credit agreement with Wells Fargo Securities, LLC, its affiliate and other lenders named therein. The credit agreement governed SSS's $10.0 million revolving credit facility and its $50.0 million senior term loan facility, each of which bore an interest rate of LIBOR plus 375 basis points and has a maturity date of September 7, 2016. As of December 31, 2012, SSS had outstanding borrowings of $8.2 million under its revolving credit facility and $48.5 million under its senior term loan facility, all of which carried an effective interest rate of 3.97% per annum. We repaid all amounts outstanding under the revolving credit and senior term loan facilities in full at the closing of our initial public offering.

On September 7, 2012, SSS and SSH entered into a third amended and restated credit agreement with LBC Credit Partners, LP and other lenders named therein. Affiliates of LBC Credit Partners, L.P. owned 1,785,420 of our common units upon the closing of our initial public offering. As of December 31, 2012, SSS had $39.6 million in outstanding borrowings bearing a cash interest rate of 12% per annum and an additional 6% per annum "in-kind" through an increase in the outstanding principal amount of the loan, as well as an additional $2.1 million bearing an interest rate of 12% per annum. Borrowings under the second lien term loan were used to repay all amounts remaining under SSS's term loan due 2014 and its subordinated loan due 2015. Future borrowings would bear cash interest at a rate of 12% per annum and PIK interest at a rate of 6% per annum. We also repaid the second lien term loan in full at the closing of our initial public offering.

On September 7, 2012, SSS, SSH and an affiliate entered into a first amended and restated credit agreement with an affiliate of Insight Equity and other lenders named therein. The credit agreement governed SSS's third lien term loan, which matured on September 7, 2017 and bore interest at a rate of 0% per annum. We repaid the third lien term loan in full at the closing of our initial public offering.

An affiliate of Insight Equity obtained a letter of credit from a financial institution in the amount of $1.5 million to provide additional security against an equity investment that LBC Credit Partners, L.P. made in SSS after Insight Equity's purchase of Superior Silica Holdings LLC. This letter of credit was retired at the closing of our initial public offering.

Affiliates of Insight Equity and LBC Credit Partners, L.P. obtained letters of credit at a financial institution on behalf of SSS to support its obligation to repay $16.0 million in advance payments provided by three sand customers at the time they entered into take-or-pay supply agreements with us. As of December 31, 2013, the outstanding balance under these letters of credit was $0. The letters of credit are reduced proportionally on a quarterly or semi-annual basis based on principal payments made as of each respective customer sales contract's annual effective date.

Procedures for Review, Approval and Ratification of Related-Person Transactions

Our code of business conduct and ethics provides that the board of directors of our general partner or its authorized committee periodically review all related person transactions that are required to be disclosed under SEC rules and, when appropriate, initially authorize or ratify all such transactions. In the event that the board of directors of our general partner or its authorized committee considers ratification of a related person transaction and determines not to so ratify, the code of business conduct and ethics provides that our management will make all reasonable efforts to cancel or annul the transaction.

The code of business conduct and ethics provides that, in determining whether or not to recommend the initial approval or ratification of a related person transaction, the board of directors of our general partner or its authorized committee should consider all of the relevant facts and circumstances available, including (if applicable) but not limited to: (i) whether there is an appropriate business justification for the transaction; (ii) the benefits that accrue to us as a result of the transaction; (iii) the terms available to

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unrelated third parties entering into similar transactions; (iv) the impact of the transaction on a director's independence (in the event the related person is a director, an immediate family member of a director or an entity in which a director or an immediately family member of a director is a partner, shareholder, member or executive officer); (v) the availability of other sources for comparable products or services; (vi) whether it is a single transaction or a series of ongoing, related transactions; and (vii) whether entering into the transaction would be consistent with the code of business conduct and ethics.

Further information required for this item is provided in Part I, Item 1. Business—Overview, Part III, Item 10. Directors, Executive Officers and Corporate Governance and Note 10, Related Party Transactions, included in the notes to the audited consolidated financial statements included in Part II, Item 8. Financial Statements and Supplementary Data.

ITEM 14.            PRINCIPAL ACCOUNTING FEES AND SERVICES

We have engaged BDO USA, LLP ("BDO") as our independent registered public accounting firm. The following table sets forth fees billed for professional serviced rendered by BDO to audit our annual financial statements and for other services in 2013 and 2012, including out-of-pocket expenses billed.

Pursuant to the charter of the Audit Committee, the Audit Committee is responsible for the oversight of our accounting, reporting and financial practices. The Audit Committee is responsible for the appointment, compensation, retention and oversight of the work of our external auditors; the pre-approval of all audit and non-audit services to be provided, consistent with all applicable laws, to us by our external auditors; and the establishment of the fees and other compensation to be paid to our external auditors. The Audit Committee also oversees and directs our internal auditing program and reviews our internal controls.

The Audit Committee has adopted a policy for the pre-approval of audit and permitted non-audit services provided by our principal independent accountants. The policy requires that all services provided by BDO, including audit services, audit-related services, tax services and other services, must be pre-approved by the Audit Committee.

The Audit Committee reviews the external auditors' proposed scope and approach as well as the performance of the external auditors. It also has direct responsibility for resolution of and sole authority to resolve any disagreements between our management and our external auditors regarding financial reporting, regularly reviews with the external auditors any problems or difficulties the auditors encounter

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in the course of their audit work, and, at least annually, uses its reasonable efforts to obtain and review a report from the external auditors addressing the following (among other items):

•

the external auditors' internal quality-control procedures;



•

any material issues raised by the most recent internal quality-control review, or peer review, of the external auditors;



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the independence of the external auditors;



•

the aggregate fees billed by the external auditors for each of the previous two fiscal years; and



•

the rotation of the external auditors' lead partner.

PART IV

ITEM 15.    EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

Schedules other than those listed above are omitted because they are not required, not material, not applicable or the required information is shown in the financial statements or notes thereto.

Agreements attached or incorporated herein as exhibits to this report are included to provide investors with information regarding the terms and conditions of such agreements and are not intended to provide any other factual or disclosure information about Emerge Energy Services LP or the other parties to the agreements.

Such agreements may contain representations and warranties by the parties to the applicable agreement. These representations and warranties have been made solely for the benefit of the other parties to the applicable agreement and (i) should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties if those statements prove to be inaccurate, (ii) have been qualified by disclosures that were made to the other party or parties in connection with the negotiation of the applicable agreement, which disclosures are not necessarily reflected in the agreement, (iii) may apply standards of materiality in a way that is different from what may be viewed as material to you or other investors and (iv) were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement and are subject to more recent developments. Accordingly, the representations and warranties in such agreements may not describe the actual state of affairs as of the date they were made or at any other time.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Date: March 24, 2014

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons in their indicated capacities, which are with the general partner of the registrant, on the dates indicated.

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INDEX TO EXHIBITS

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