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

Emerge Energy Services LP
(Exact Name of Registrant as Specified in Its Charter)

Approximate date of commencement of proposed sale to the public: As soon as practicable after this Registration Statement becomes effective.

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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):

The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

The information in this preliminary prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This preliminary prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.

This is the initial public offering of our common units representing limited partner interests. We are offering common units in this offering. No public market currently exists for our common units. We currently expect that the initial public offering price will be between $ and $ per common unit.

We have applied to list our common units on the New York Stock Exchange under the symbol "EMES."

Investing in our common units involves risks. See "Risk Factors" beginning on page 29 of this prospectus.

We are an emerging growth company under applicable Securities and Exchange Commission rules and are eligible for, and are relying on, certain reduced public company reporting requirements. See "Summary—Implications of Being an Emerging Growth Company" on page 18 of this prospectus.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

We have granted the underwriters a 30-day option to purchase up to an additional common units from us on the same terms and conditions as set forth above if the underwriters sell more than common units in this offering.

The underwriters expect to deliver the common units to purchasers on or about , 2013 through the book-entry facilities of The Depository Trust Company.

You should rely only on the information contained in this prospectus, any free writing prospectus prepared by or on behalf of us or any other information to which we have referred you in connection with this offering. We have not, and the underwriters have not, authorized any other person to provide you with information different from that contained in this prospectus. Neither the delivery of this prospectus nor the sale of common units means that information contained in this prospectus is correct after the date of this prospectus. This prospectus is not an offer to sell or the solicitation of an offer to buy the common units in any circumstances under which the offer or solicitation is unlawful.

The market data and certain other statistical information used throughout this prospectus are based on independent industry publications, government publications or other published independent sources. Some data is also based on our good faith estimates. Although we believe these third-party sources are reliable and that the information is accurate and complete, we have not independently verified such information and there can be no assurance as to the completeness or accuracy of such information.

Unless the context otherwise requires, financial and operating data presented in this prospectus on a pro forma basis consist of the combined results of SSS and AEC, which together constitute our predecessor for accounting purposes, as if such combination occurred on January 1, 2010 and give effect to the acquisition of Direct Fuels as if such acquisition occurred on December 31, 2012 for pro forma balance sheet purposes and January 1, 2012 for purposes of all other pro forma financial statements. SSS and AEC are, prior to the completion of this offering, under the common control of a private equity fund managed and controlled by Insight Equity Management Company LLC and, as a result, their contribution to us will be recorded as a combination of entities under common control, whereby the assets and liabilities sold and contributed are recorded based on their historical carrying value. Direct Fuels is not under common control with SSS and AEC and, as a result, the contribution of Direct Fuels to us will be accounted for as an acquisition, whereby the assets and liabilities sold and contributed are recorded at their fair values on the date of contribution.

SUMMARY

This summary provides a brief overview of information contained elsewhere in this prospectus. This summary does not contain all of the information that you should consider before investing in our common units. You should read the entire prospectus carefully, including the historical and pro forma financial statements and the notes to those financial statements included in this prospectus. Unless indicated otherwise, the information presented in this prospectus assumes an initial public offering price of $ per common unit (the midpoint of the price range set forth on the cover page of this prospectus) and that the underwriters' option to purchase additional common units is not exercised. You should read "Risk Factors" beginning on page 29 for more information about important risks that you should consider carefully before buying our common units. We include a glossary of some of the terms used in this prospectus as Appendix B.

References in this prospectus to "Emerge Energy Services," "we," "our," "us," "the Partnership" or like terms refer to Emerge Energy Services LP and its wholly owned subsidiaries after giving effect to the transactions described under "—Partnership Structure and Offering-Related Transactions" beginning on page 14. References in this prospectus to "Emerge GP" refer to Emerge Energy Services GP LLC, our general partner. References in this prospectus to "Insight Equity" refer to Insight Equity Management Company LLC and its affiliated investment funds and its controlling equity owners. We conduct our Sand operations through our subsidiary Superior Silica Sands LLC, or SSS, and our Fuel Processing and Distribution operations through our subsidiaries Allied Energy Company LLC, or AEC, and Insight Equity Acquisition Partners, LP, which we call Direct Fuels. Please read "Certain Definitions" beginning on page v for information on additional defined terms we use in this prospectus.

Overview

We are a growth-oriented limited partnership recently formed by management and affiliates of Insight Equity to own, operate, acquire and develop a diversified portfolio of energy service assets. We believe this diversification provides a more stable cash flow profile compared to companies with operations in only one business or one location. Our operations are organized into two service oriented business segments:

•: Sand, which primarily consists of mining and processing frac sand, a key component used in hydraulic fracturing of oil and natural gas wells; and
•: Fuel Processing and Distribution, which primarily consists of acquiring, processing and separating the transportation mixture, or transmix, that results when multiple types of refined petroleum products are transported sequentially through a pipeline.

Our Sand segment is expanding rapidly and we expect it to continue to provide a significant majority of our cash available for distribution in the future.

Summary of Key Strengths

Sand Segment

•: Large reserve of high quality coarse frac sand
•: Efficient logistics network
•: Low cost operating structure
•: Significant organic growth capacity
•: Highly experienced management team

Fuel Processing and Distribution Segment

•: Strong regional market position in Dallas-Fort Worth and Birmingham
•: Low cost operating structure
•: Highly experienced management team

Sand Segment Overview

Market Dynamics

Advances in unconventional oil and natural gas extraction techniques, such as horizontal drilling and hydraulic fracturing, have allowed for significantly greater extraction of oil and natural gas trapped within unconventional resource basins such as shale rock. In the hydraulic fracturing process, granular material, called proppant, is suspended and transported in the fluid and fills the fracture, "propping" it open once high-pressure pumping stops, allowing for the hydrocarbons to flow freely to the wellhead. Frac sand represents the lowest cost and largest volume of proppant supplied to pressure pumping companies and operators. According to a report by the Freedonia Group dated March 1, 2012, which we refer to as the Freedonia Report, North American raw frac sand demand, by weight, grew 29% per year from 2006 to 2011 and is expected to grow 7.3% per year from 2011 to 2016.

Historical and Projected Proppant Demand and Raw Frac Sand Price

Source: The Freedonia Group

Frac sand must meet stringent requirements for grain size, crush strength and sphericty in addition to several other important criteria as determined by the American Petroleum Institute, or API. Larger, coarser sand grains (such as 16/30, 20/40 and 30/50 mesh) are typically used in hydraulic fracturing processes targeting oil and liquids-rich natural gas recovery, while smaller, finer grains (such as 40/70 and higher mesh) are used primarily in dry natural gas drilling applications. Deposits of coarse sand that satisfy API standards are predominantly found in the upper Midwest, with the greatest concentration in the state of Wisconsin. Although the exploration and production industry is cyclical and oil prices have historically been volatile, we believe that many of the domestic oil and liquids-rich natural gas plays are economically attractive at prices substantially below the current prevailing prices for oil- and liquids-rich natural gas. We believe this should provide continued and growing opportunities for drilling activity in oil- and liquids-rich natural gas formations and continued growth in demand for coarser frac sands.

Facilities

Our Sand segment consists of facilities in New Auburn, Wisconsin, Barron County, Wisconsin and Kosse, Texas that are optimized to exploit the reserve profile in place at each location and produce

high-quality frac sand. Our Wisconsin sand reserves at our New Auburn and Barron facilities provide 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 also 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 Ottawa white deposits located in Wisconsin's Jordan, St. Peter and Wonewoc formations. According to a report published February 6, 2013 by PropTester®, Inc. and KELRIK, LLC, which we refer to as the PropTester® Report, many of the northern Ottawa white deposits in these formations contain less than 30% 40 mesh and coarser substrate. However, our sample boring data has 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, which along with other coarse sands is currently subject to high demand from our customers. The coarseness of our reserves also provides us with a meaningful cost advantage, as companies with a low concentration of coarse sand must expend the resources necessary to mine a large amount of fine grain sand that currently has little 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 New Auburn dry plant facility has a rated production capacity of 4,200 tons per day, or roughly 40 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. We also have 4.5 miles of existing rail track that connects our facility to the Union Pacific rail line and provides us with shipping access to all of the major shale basins 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. 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. 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.

Our Barron facility currently consists of a sand mine and a wet plant on land that we currently lease and a dry plant on land that we own. This facility has a rated production capacity of 8,800 tons per day, 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. We utilize 3.1 miles of existing rail track that connects our facility to the rail line owned by the Canadian National Railway Company, or Canadian National, making our Barron facility one of only two active Wisconsin-based frac sand mines, and the only one with significant available capacity for future production growth, located on the Canadian National line. Our direct connection to the Canadian National line allows us to offer direct access to the rapidly growing oil and gas shale plays in northwestern Canada and the northeastern United States. In addition, we are currently the only frac sand provider in Wisconsin located on Canadian National's high-capacity rail line designed for rail cars with a 286,000 pound capacity, which will allow us to transport heavier loads and result in reduced transportation costs relative to competitors that only have access to lower capacity infrastructure.

We expect to construct a second wet plant at our Barron facility in order to increase our production capacity. We currently anticipate that this second wet plant will become operational in the first half of 2014 and will have the capacity to process 1.2 million tons of wet sand per year when completed. We have identified a property suitable for use as the site of the second wet plant, which we expect will provide us access to the same wide range of high-quality sand that we currently have through our existing Wisconsin facilities.

We also mine frac sand at our facility in Kosse, Texas that is processed into a high-quality, 100 mesh frac sand, generally used in dry gas drilling applications. In favorable pricing markets, washed sand is shipped from our Wisconsin operations in unit trains to Kosse where it is dried, screened and resold to oil field service companies servicing the unconventional resource plays located in south and west Texas. As a result of the quality and diversity of our sand reserves, we have the operational flexibility to alter a portion of our produced sand mix to meet customer needs as the market prices for crude oil and natural gas adjust in the future.

The following table provides information regarding our current and planned frac sand production facilities as of December 31, 2012.

Mine/Plant Location	Proven Recoverable Reserves (Tons)(1)				Depth of Reserves				Mine Area			Wet Plant Capacity (Tons)			Dry Plant Capacity (Tons)			Year Ended December 2012 Sales Volume (Tons)

	(millions)				(feet)				(acres)			(thousands)			(thousands)			(thousands)
New Auburn, WI		24.6		14-60 mesh		45-105	March 2036			418			2,000			1,300	4.5 miles		1,061.2
Barron County, WI		22.0	(2)	14-50 mesh		40-50	July 2037			262	(3)		2,900	(4)		2,400	3.1 miles		11.9
Kosse, TX		28.5		20-140 mesh		100	N/A	(5)		225			1,500			600	N/A		149.3	(6)

(1): Reserves are estimated as of June 30, 2012 by third-party independent engineering firms based on core drilling results and in accordance with the SEC's definitions of proven recoverable reserves and related rules for companies engaged in significant mining activities.
(2): Does not include the sand reserves to which we have access pursuant to our ten-year supply agreement with Midwest Frac.
(3): Consists of five adjacent mineral deposits.
(4): Consists of two wet plants, one of which is scheduled to be constructed in the first half of 2014, and includes 500,000 tons of wet sand that we have the right to purchase from Midwest Frac.
(5): We own the mineral rights to at our Kosse mine.
(6): Includes sales of sand mined in Wisconsin and processed in our Kosse facility and shortfall sales pursuant to our take-or-pay contract with one of our customers. Please see "Business—Our Assets and Operations—Kosse, Texas Operations."

Sand Customers

The core customers for our Wisconsin facilities are major oilfield services companies engaged in hydraulic fracturing. New Auburn's two largest customers, Schlumberger Technology Corporation, or Schlumberger, and a wholly owned subsidiary of Baker Hughes Oilfield Operations, Inc. or Baker Hughes, together represented approximately 83% of this facility's processed sand volumes in the year ended December 31, 2012. These customers have signed multi-year take-or-pay contracts that include provisions requiring the customer to pay us an amount designed to compensate us, in part, for our lost margins for the applicable contract year in the event the customer does not take delivery of the minimum annual volume of frac sand specified in the contract. Any sales of the shortfall volumes to other customers on the spot market would provide us with additional margin on these volumes.

place for 9% of our 2.4 million tons of annual production capacity at our Barron facility, efforts-based contractual volume accounts for 8% and 10% in tolling agreements. As of December 31, 2012, the product mix-weighted average price of sand sold from our Barron facility pursuant to these contracts was $55 per ton and the weighted average remaining duration of these contracts was approximately 5.6 years, or 2.2 years if the termination provision described above is exercised as soon as it becomes available. These averages do not include any volumes under our ten year tolling agreement with Midwest Frac. Should market trends continue to develop as we expect, 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.

As the frac sand industry has developed in the past few years, major oilfield service and certain oil and gas companies have entered into long-term take-or-pay contracts to secure a dedicated source of frac sand supply for their operations. However, as a result of recent expansions in the supply of frac sand and the possibility of continued expansions, we believe that frac sand customers may be increasingly reluctant to enter into take-or-pay contracts that expose the customer to pre-determined financial liability for failure to take delivery of minimum volumes of frac sand. Customers may increasingly pursue fixed-volume contracts or efforts-based contracts that do not commit the customer to take delivery of specified volumes of frac sand. 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. Please read "Risk Factors—Risks Related to Our Business—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."

Cost Structure

Producing dry sand suitable for sale as a proppant involves three distinct operations:

•: Mining. This involves the removal of overburden and the subsequent excavation of reserves to be further processed.
•: Wet Processing. Mined reserves are mixed with water to facilitate movement by pipeline from the mine to the wet plant. At the wet processing facility, the wet sand is screened to eliminate particles that are larger than desired. There is also a gravity separation process that removes fine impurities that have no commercial value. The remaining product is stored in large stockpiles.
•: Dry Processing. Wet sand is transported by truck to the drying facility. Very large dryers remove the moisture after which the dried sand is sorted by size and stored in silos before being loaded onto rail cars or trucks for transportation to customers.

We believe our cost structure puts us in an attractive position relative to other producers of frac sand. The coarseness of our reserves means that a very large proportion of the sand that we mine ends up as saleable dry sand, which is not possible for producers whose deposits do not have as high a proportion of coarse sand. Our advanced wet and dry plants, including enclosed dry plants in Wisconsin, allow us to efficiently produce frac sand at full run rates throughout the year. The royalties that we paid to the landowners of our mines were less than 1% of our revenues in 2011 and 2.4% in 2012. Additionally, once we have satisfied 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. As a result, for certain types of expenses, we incur costs only when we are producing saleable frac sand.

Fuel Processing and Distribution Segment Overview

Market Dynamics

The primary driver of activity and earnings in our Fuel Processing and Distribution segment is our transmix operations. The transmix industry consists of businesses that process and separate transportation mixture, which is the liquid interface, or fuel mixture, that forms when multiple types of petroleum products are transported sequentially through a pipeline. Pipeline operators send large batches of different fuel products (such as gasoline, diesel and jet fuel) through the same pipeline, in sequence, to receiving terminals. Product batches are placed directly against each other, without any practical means of keeping them separated; as a result, some mixing of fuels occurs at the interface of different batches in a pipeline. Transmix must be processed in order to separate it into useable gasoline and diesel fuel that can be used in cars, trucks, locomotives and other similar equipment. The Energy Information Administration estimates that 19.2 million barrels per day of liquid petroleum products were consumed in the United States in 2010 with the vast majority being transported by pipeline. We believe that approximately 0.5% of the petroleum products transported by refined product pipelines becomes transmix and is sold to companies such as ours for refinement, which would imply a transmix market size of approximately 85,000 barrels per day.

Asset Overview

Our Fuel Processing and Distribution 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. In addition to processing transmix and selling the resulting refined products, we provide a suite of complementary fuel products and services, including third-party terminaling services, the selling of wholesale petroleum products, certain reclamation services (which consist primarily of tank cleaning services) and blending of renewable fuels.

The following table provides information regarding our Fuel Processing and Distribution assets and volumes as of and for the year ended December 31, 2012.

Plant Location	Owned Acreage

	(in thousands, except acreage data)
Dallas-Fort Worth, TX		20	107,310	94,831	13,347	11,990	N/A
Birmingham, AL		40	76,650	22,502	153,949	21,966	10,000

While a meaningful portion of our transmix business is conducted on a spot basis, we currently purchase approximately 63% of our supply of transmix pursuant to exclusive contracts having a volume-weighted average remaining duration of 17 months as of December 31, 2012. We also purchase a significant amount of gasoline and diesel in bulk every month as part of our wholesale fuel business, and then sell that fuel to local unbranded customers who value our combination of pricing and convenience. We design the contract structure of both our transmix and wholesale businesses to capture a stable margin, as the price differential between the indices at which we purchase fuel and the sales price of the corresponding refined products tends to be stable.

Financial Overview

For the year ended December 31, 2012, we generated unaudited pro forma net income and unaudited pro forma Adjusted EBITDA of approximately $27.1 million and $52.3 million, respectively. Our Sand segment comprised 65% of our unaudited pro forma Adjusted EBITDA in this period. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to its most directly comparable financial measures calculated and presented in accordance with generally accepted

accounting principles, or GAAP, please read "—Summary Historical and Pro Forma Financial and Operating Data—Non-GAAP Financial Measures" beginning on page 26.

Business Strategies

The primary components of our business strategy are:

•: Focus on Business Results and Total Distributions. The board of directors of our general partner will adopt a policy under which distributions for each quarter will equal the amount of available cash (as described in "Cash Distribution Policy and Restrictions on Distributions") we generate each quarter. We expect to focus on optimizing our business results and maximizing total distributions, rather than attempting to manage our results with a focus on making minimum distributions. We do not intend to maintain excess distribution coverage in order to stabilize our quarterly distributions or to otherwise reserve cash for future distributions. In addition, our general partner has a non-economic general partner interest and no incentive distribution rights, and, accordingly, our unitholders will receive 100% of our cash distributions. See "Our Cash Distribution Policy and Restrictions on Distributions" beginning on page 66.
•: Seek contractual cash flow stability. In our Sand segment, we intend to generate stable cash flows by continuing to secure long-term contracts with existing and new customers that will cover the substantial majority of our production capacity. A portion of our long-term contracts at our New Auburn and Barron facilities are take-or-pay supply agreements that are designed to compensate us, in part, for our lost margins for the applicable contract year on any unpurchased minimum annual volumes of frac sand thereunder. Subject to market conditions, we will continue to pursue long-term contracts under which our customers commit to take shipments of specified minimum amounts of frac sand to enhance the stability of our cash flows and mitigate our direct exposure to commodity price fluctuations. As of December 31, 2012, our northern Ottawa white sand contracts had a volume-weighted average remaining term of 5.1 years, assuming that one of our customers does not exercise its early termination right described elsewhere in this prospectus, and a volume and product mix-weighted price of $54 per ton. Should the customer exercise its early termination right as soon as it becomes available under the contract, the weighted average remaining duration of the contracts would be 1.7 years. These averages do not include any volumes under our ten year tolling agreement with Midwest Frac.

In our Fuel Processing and Distribution 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 fairly 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 enter into financial hedging arrangements in order to limit our direct exposure to commodity price and market index fluctuations.

•: 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 recently commenced operations at a third frac sand production facility in Barron County, which more than doubled our dry production capacity and the amount of proven recoverable Wisconsin reserves we can access. As of the date of this prospectus, we have contracted to sell 650,000 tons of annual frac sand volume, which accounts for 27% of the plant's 2.4 million tons per year capacity. Take-or-pay and fixed-volume contracts represent 9% of the plant's yearly capacity, efforts-based contractual volume accounts for 8% and tolling agreements account for another 10%. We believe our additional frac sand production capacity should provide us with significant opportunities to secure additional long-term contracts or to make spot sales at market prices,

which have been higher than long-term contract prices in the recent past. If we are successful in taking advantage of these opportunities, we expect our profitability and cash flows will be positively impacted. In our Fuel Processing and Distribution segment, we believe there are several opportunities to contract additional transmix supplies and increase wholesale volume, which we can process using existing excess capacity.

•: 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 have developed a total supply chain solution for our customers, which we believe will provide them with a streamlined order process and a lower total delivered product cost while generating incremental revenue for us and enabling us to reach a broader set of customers. In our Fuel Processing and Distribution segment, we have started producing biodiesel at our Birmingham, Alabama location using recommissioned assets. Also, we intend to leverage our existing customer relationships to expand our footprint in Dallas-Fort Worth and Birmingham and their adjacent markets.
•: 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 high-quality frac sand. Over the past five years, the demand for frac sand in the United States 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. We believe frac sand supply will continue to be constrained by 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 API, as well as challenges associated with locating contiguous reserves of frac sand large enough to justify the capital investment required to develop a mine and processing plant and securing necessary local, state and federal permits required for operations. From 2011 to 2016, the demand and price of raw frac sand are expected to grow 7.3% and 4.7% annually, respectively, according to the Freedonia Report.
•: 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 in properties adjacent to or in close proximity to our existing Wisconsin operations, allowing for the opportunity to contract additional reserves. We also believe that we can replicate our transmix, wholesale and terminal business activities successfully in other regions of the United States.
•: 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. At the closing of this offering, and after giving effect to the offering-related transactions we describe in this prospectus, we expect to have approximately $ million of cash on hand and $ million of available borrowing capacity under our anticipated new revolving credit facility.

Competitive Strengths

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

•: High quality, strategically located assets. We currently operate three scalable frac sand production facilities in New Auburn, Wisconsin, Barron County, Wisconsin and Kosse, Texas. Our facilities in Wisconsin are supported by approximately 46.6 million tons of proven recoverable sand reserves and our facility in Texas is supported by approximately 28.5 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 Ottawa white deposits located in Wisconsin's Jordan, St. Peter and Wonewoc formations. According to the PropTester® Report, many of the northern Ottawa white deposits in these formations contain less than 30% 40 mesh and coarser substrate with our Barron reserves being comprised of more than 60% 50 mesh or coarser substrate. However, our sample boring data has indicated that our Wisconsin reserves contain deposits of nearly 35% 40 mesh or coarser substrate. We are also one of a select number of mine operators that can offer commercial amounts of 16/30 mesh sand, the coarsest grade of widely-used frac sand on the market. Our 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 Processing and Distribution 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.

•: 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 our lost margins for the applicable contract year on any minimum annual volumes not purchased by that customer. Any sales of the shortfall volumes to other customers on the spot market would provide us with additional margin on these volumes. Collectively, sales to customers with take-or-pay sales agreements in 2011 and 2012 accounted for approximately 79% and 89% of our total Sand segment sales volumes, respectively.

In our Fuel Processing and Distribution 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 approximately 63% of our supply of transmix pursuant to exclusive contracts with terms ranging from 12 to 36 months, with a volume-weighted average remaining duration of 17 months as of December 31, 2012. In addition, we have throughput agreements with major refining and fuel marketing companies with terms of up to 36 months, which provide stable, fee-based revenue.

•

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 shale basins. Our New Auburn facility has 4.5 miles of on-site rail track that is tied into a rail line owned by Union Pacific and our Barron facility has 3.1 miles of on-site rail track tied into a Canadian National rail line. 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 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. Given our multiple railroad and barging logistics capabilities, we have started to explore potential sales opportunities in Central and South American countries. 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.

•

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:

•: significant coarse mineral reserve composition that minimizes yield loss;
•: close proximity of our silica reserves to our processing plants, which reduces operating costs;
•: expertise in designing, building, maintaining and operating advanced frac sand processing, storage and loading facilities and transmix processing and storage assets;
•: 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;
•: proximity to major sand and fuel logistics infrastructure, minimizing transportation and fuel costs and headcount needs;
•: mineral royalties paid that were less than 2.4% of our Sand revenues in 2012;
•: enclosed dry plant operations to allow full run rates in winter months, increasing plant utilization; and
•: a customer base spread across a variety of markets, allowing us to maximize our asset utilization.

•

Significant organic growth capacity. We believe we have a significant pipeline of attractive sales opportunities for our Barron County facility, which commenced commercial operations in December 2012. As of the date of this prospectus, we have contracted to sell 650,000 tons of annual frac sand volume, which accounts for 27% of the plant's 2.4 million tons per year capacity. Take-or-pay and fixed-volume contracts represent 9% of the plant's yearly capacity, efforts-based contractual volume accounts for 8% and tolling agreements account for another 10%. We expect to use this excess capacity to establish new customer relationships through new long-term contracts and to enter into spot sales at market prices, which have been higher than long-term contract prices in the recent past. If we are successful in establishing these relationships or selling into the spot market at favorable prices, we expect to experience a positive impact on our profitability and cash flows. In addition, we believe that this capacity will 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.

•

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. Three of the four largest hydraulic fracturing service providers have committed to multi-year contracts to purchase frac sand from us, including our take-or-pay contracts with Schlumberger and Baker Hughes, and 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 similar arrangements in the future. In our Fuel Processing and Distribution 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.

•: 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, at our Wisconsin facilities, we have been able to optimize our production mix so that up to 20% of our production volume can fluctuate between coarse and fine sands without significant impact on our production yields or costs, 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.
•: 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 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. The top five management team members of our Fuel Processing and Distribution 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 Relationship with Insight Equity

Over % of the equity interests in Emerge GP is indirectly owned by Insight Equity, with the balance owned by our current officers and employees, and other private investors. Founded in 2002, Insight Equity makes control investments in strategically viable, middle market, asset-intensive companies across a wide range of industries. Insight Equity has committed approximately $425 million to 12 investments in North America. As the majority owner of our general partner and the direct or indirect owner of approximately % of our outstanding common units, Insight Equity has a strong incentive to support and promote the successful execution of our business plan.

Risk Factors

An investment in our common units involves risks. Below is a summary of certain key risk factors that you should consider in evaluating an investment in our common units. This list is not exhaustive. Please read the full discussion of these risks and other risks described under "Risk Factors."

Risks Related to Our Business

•: We may not have sufficient available cash to pay any quarterly distribution on our common units.
•: The assumptions underlying our estimate of cash available for distribution described in "Our Cash Distribution Policy and Restrictions on Distributions" are inherently uncertain and subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those forecasted.
•: 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 Sand operations are subject to operating risks that are often beyond our control and could adversely affect production levels and costs.
•: A large portion of our sales in each of our Sand segment and our Fuel Processing and Distribution 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.
•: 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 will not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time.
•: The board of directors of our general partner may modify or revoke our cash distribution policy at any time at its discretion, including in such a manner that would result in an elimination of cash distributions regardless of the amount of available cash we generate. Our partnership agreement does not require us to pay any distributions at all.
•: 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.
•: 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.
•: 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.

Risks Inherent in an Investment in Us

•: The board of directors of our general partner will adopt a policy to distribute an amount equal to the available cash we generate each quarter, which could limit our ability to grow and make acquisitions.
•: Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors.

Partnership Structure and Offering-Related Transactions

We were formed in April 2012 as a Delaware limited partnership. Insight Equity currently indirectly holds all of our limited partner interests. In order to maximize operational flexibility, we will conduct our operations through subsidiaries. At or prior to the closing of this offering, the following transactions, which we refer to as the offering-related transactions, will occur:

•: SSH will convey a % interest in SSS to our general partner as a capital contribution;
•: AEC Holdings will convey a % interest in AEC to our general partner as a capital contribution;
•: DF Parent will convey a % interest in Direct Fuels to our general partner as a capital contribution accounted for by the predecessor using the acquisition method of accounting;
•: DF will redeem its preferred units for $ million using its revolving credit facility;
•: Our general partner will convey those interests in SSS, AEC and Direct Fuels to us in exchange for a non-economic general partner interest in us;
•: SSH will convey its remaining interest in SSS to us in exchange for (i) common units, representing a % limited partner interest in us, and (ii) the right to receive $ million in cash, in part, as reimbursement for certain capital expenditures;
•: AEC Holdings will convey its remaining interest in AEC to us in exchange for (i) common units, representing a % limited partner interest in us, (ii) the right to receive $ million in cash, in part, as reimbursement for certain capital expenditures and (iii) our assumption of AEC Holdings' existing debt;
•: DF Parent will convey its remaining interest in Direct Fuels to us in exchange for (i) common units, representing a % limited partner interest in us, and (ii) the right to receive $ million in cash, in part, as reimbursement for certain capital expenditures;
•: We will issue common units to the public, representing a % limited partner interest in us;
•: We will convey our interests in SSS, AEC and Direct Fuels to Emerge Energy Services Operating LLC, our operating subsidiary;
•: We will enter into a new $ million revolving credit facility, from which we will borrow $ million; and
•: We will use the net proceeds from this offering and the borrowings under our anticipated new revolving credit facility as set forth under "Use of Proceeds."

If the underwriters do not exercise their option to purchase additional common units, we will issue an additional common units to Insight Equity and other private investors at the expiration of the option for no additional consideration. If and to the extent the underwriters exercise their option to purchase additional common units, the number of common units purchased by the underwriters pursuant to any exercise will be sold to the public, and any remaining common units not purchased by the underwriters pursuant to any exercise of the option will be issued to Insight Equity and other private investors at the expiration of the option period. Accordingly, the exercise of the underwriters' option to purchase additional common units will not affect the total number of units outstanding.

Our Management

Our general partner has the sole responsibility for conducting our business and for managing our operations and is controlled by Insight Equity. Our general partner will not receive any management fee or other compensation in connection with the management of our business or this offering, but it will be entitled to reimbursement of all direct and indirect expenses incurred on our behalf, which we expect to be approximately $ for the year ending December 31, 2013. Our partnership agreement provides that our general partner will determine in good faith, meaning that it subjectively believes that such determination is in our best interests, the expenses that are allocable to us.

The board of directors of our general partner will initially be comprised of seven members, all of whom will be designated by Insight Equity and three of whom will be independent. Neither our general partner nor its board of directors will be elected by our unitholders. Insight Equity will have the right to appoint our general partner's entire board of directors, including the independent directors.

Principal Executive Offices and Internet Address

We were formed as a Delaware limited partnership in April 2012 under the name Emergent Energy Services LP. We subsequently amended our certificate of limited partnership to change our name to Emerge Energy Services LP. Our principal executive offices are located at 1400 Civic Place, Suite 250, Southlake, Texas and our telephone number is (817) 488-7775. Our website is located at and will be activated in connection with the closing of this offering. We will make our periodic reports and other information filed with or furnished to the Securities and Exchange Commission, or the SEC, available, free of charge, through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

Summary of Conflicts of Interest and Duties

Our general partner has a duty to manage us in a manner it subjectively believes is in our best interests. However, the officers and directors of our general partner also have duties to manage our general partner in a manner beneficial to its majority owner, Insight Equity. Certain of the officers and directors of our general partner are also officers and directors of Insight Equity or its subsidiaries. As a result, conflicts of interest will arise in the future between us and holders of our common units, on the one hand, and Insight Equity and our general partner, on the other hand. For example, our general partner will be entitled to make determinations that affect the amount of distributions we make to the holders of common units.

Delaware law provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties owed by the general partner to limited partners and the partnership. Pursuant to these provisions, our partnership agreement contains various provisions replacing the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing the duties of the general partner and the methods of resolving conflicts of interest. The effect of these provisions is to restrict the remedies available to our common unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty. Our partnership agreement also provides that affiliates of our general partner, including Insight Equity and its subsidiaries and affiliates, are permitted to compete with us. By purchasing a common unit, the purchaser agrees to be bound by the terms of our partnership agreement, and each common unitholder is treated as having consented to various actions and potential conflicts of interest contemplated in the partnership agreement that might otherwise be considered a breach of fiduciary or other duties under applicable state law.

For a more detailed description of the conflicts of interest and the duties of our general partner, please read "Conflicts of Interest and Duties" beginning on page 180.

Implications of Being an Emerging Growth Company

As a company with less than $1.0 billion in revenue during its last fiscal year, we qualify as an "emerging growth company" as defined in the Jumpstart Our Business Startups Act of 2012, or the JOBS Act. An emerging growth company may take advantage of specified reduced reporting and other regulatory requirements for up to five years that are otherwise applicable generally to public companies. These provisions include:

•: A requirement to have only two years of audited financial statements and only two years of related Management's Discussion and Analysis of Financial Condition and Results of Operations;
•: Exemption from the auditor attestation requirement in the assessment of the emerging growth company's internal control over financial reporting;
•: Exemption from the adoption of new or revised financial accounting standards until they would apply to private companies;
•: Exemption from compliance with any new requirements adopted by the Public Company Accounting Oversight Board requiring mandatory audit firm rotation or a supplement to the auditor's report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer; and
•: Reduced disclosure about the emerging growth company's executive compensation arrangements.

We will cease being an emerging growth company if we have more than $1.0 billion in annual revenues, have more than $700 million in market value of our common units held by non-affiliates, or issue more than $1.0 billion of non-convertible debt over a three-year period.

We have elected to comply with the reduced disclosure requirements described above and we may elect to avail ourselves of other reduced reporting requirements in future filings. As a result of these elections, the information that we provide in this prospectus may be different from the information you may receive from other public companies in which you hold equity interests.

The Offering


Common units offered to the public		common units.
		common units, if the underwriters exercise in full their option to purchase additional common units.
Units outstanding after this offering		common units representing a % limited partner interest in us. If the underwriters do not exercise their option to purchase additional common units, we will issue an additional common units to Insight Equity and other private investors at the expiration of the option for no additional consideration. If and to the extent the underwriters exercise their option to purchase additional common units, the number of common units purchased by the underwriters pursuant to any exercise will be sold to the public, and any remaining common units not purchased by the underwriters pursuant to any exercise of the option will be issued to Insight Equity and other private investors at the expiration of the option period. Accordingly, the exercise of the underwriters' option to purchase additional common units will not affect the total number of units outstanding.
Use of proceeds		We expect to receive net proceeds from the issuance and sale of common units offered by this prospectus of approximately $ million, after deducting underwriting discounts and commissions and the structuring fee, but before paying offering expenses.
		We will use the net proceeds from this offering (excluding the net proceeds from any exercise of the underwriters' option to purchase additional common units) to:
		• distribute $ million, $ million and $ million to SSH, AEC Holdings and DF Parent, respectively, a portion of which will be used to reimburse them for certain capital expenditures they incurred with respect to assets they contributed to us;
		• contribute $ million to SSS to repay all $ million of SSS's existing debt;
		• repay all $ million of AEC Holdings' existing debt;
		• contribute $ million to Direct Fuels to repay all $ million of Direct Fuels' existing debt;
		• contribute $ million to our operating subsidiary;
		• pay $ million of cash-based compensation awards to senior management at SSS, AEC and Direct Fuels; and
		• pay estimated offering expenses of $ million.


		Immediately following the repayment of the outstanding balance of SSS's, AEC Holdings' and Direct Fuels' existing debt with the net proceeds of this offering, we will enter into a new revolving credit facility and borrow approximately $ million under that revolving credit facility. We will use the proceeds from these borrowings to (i) make distributions of $ million, $ million and $ million to SSH, AEC Holdings and DF Parent, respectively, and (ii) pay fees and expenses of approximately $ million relating to our anticipated new revolving credit facility.
		If the underwriters exercise their option to purchase additional common units in full, the additional net proceeds will be approximately $ million. All of the net proceeds from any exercise of such option will be used to make an additional cash distribution to Insight Equity and other private investors.
		An affiliate of one of the underwriters is a lender under AEC Holdings' credit facility and will receive a portion of the net proceeds from this offering. See "Underwriting."
Cash distributions		Within 60 days after the end of each quarter, beginning with the quarter ending June 30, 2013, we expect to make distributions to unitholders of record on the applicable record date. We expect our first distribution will include available cash (as described below) for the period from the closing of this offering through June 30, 2013.
		The board of directors of our general partner will adopt a policy pursuant to which distributions for each quarter will be in an amount equal to the available cash we generate in such quarter. Available cash for each quarter will be determined by the board of directors of our general partner following the end of such quarter. We expect that available cash for each quarter will generally equal our cash flow from operations for the quarter, less cash needed for maintenance capital expenditures, accrued but unpaid expenses, reimbursement of expenses incurred by our general partner and its affiliates, debt service and other contractual obligations and reserves for future operating or capital needs that the board of directors of our general partner deems necessary or appropriate.
		We do not intend to maintain excess distribution coverage for the purpose of maintaining stability or growth in our quarterly distribution or to otherwise reserve cash for distributions, and we do not intend to incur debt to pay quarterly distributions. We expect to finance substantially all of our growth externally, either by debt issuances or additional issuances of equity.


		Because our policy will be to distribute an amount equal to all available cash we generate each quarter, our unitholders will have direct exposure to fluctuations in the amount of cash generated by our business. We expect that the amount of our quarterly distributions, if any, may vary based on our operating cash flow during such quarter. As a result, our quarterly distributions, if any, may not be stable and may vary from quarter to quarter as a direct result of variations in, among other factors, (i) our operating performance, (ii) cash flows caused by, among other things, the prices we receive for finished products, working capital needs or capital expenditures and (iii) cash reserves deemed necessary or appropriate by the board of directors of our general partner. Such variations in the amount of our quarterly distributions may be significant. Unlike most publicly traded partnerships, we will not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time. The board of directors of our general partner may change our distribution policy at any time. Our partnership agreement does not require us to pay distributions to our unitholders on a quarterly or other basis.
		Based upon our forecasted results for the twelve months ending March 31, 2014, and assuming the board of directors of our general partner declares distributions in accordance with our cash distribution policy, we expect that our aggregate distributions for the twelve months ending March 31, 2014 will be approximately $ million, or $ per common unit. See "Our Cash Distribution Policy and Restrictions on Distributions—Estimated Cash Available for Distribution for the Year Ending March 31, 2014" beginning on page 70.
		Unanticipated events may occur that could materially adversely affect the actual results we achieve during the forecast periods. Consequently, our actual results of operations, cash flows, financial condition and our need for cash reserves during the forecast periods may vary from the forecast, and such variations may be material. Prospective investors are cautioned not to place undue reliance on our forecast and should make their own independent assessment of our future results of operations, cash flows and financial condition. See "Risk Factors" beginning on page 29.
Subordinated units		None.
Incentive Distribution Rights		None.
Issuance of additional units		We can issue an unlimited number of units without the consent of our unitholders. Please read "Units Eligible for Future Sale" beginning on page 204 and "The Partnership Agreement—Issuance of Additional Partnership Interests" beginning on page 194.


Limited voting rights		Our general partner will manage and operate us. Unlike the holders of common stock in a corporation, our unitholders will have only limited voting rights on matters affecting our business. Our unitholders will have no right to elect our general partner or its directors on an annual or continuing basis. Our general partner may not be removed except by a vote of the holders of at least 66²/3% of the outstanding units voting together as a single class, including any units owned by our general partner and its affiliates, including Insight Equity. Upon consummation of this offering, Insight Equity will own an aggregate of % of our common units. This will give Insight Equity the ability to prevent the involuntary removal of our general partner. Please read "The Partnership Agreement—Voting Rights" beginning on page 191.
Limited call right		If at any time our general partner and its affiliates own more than 80% of the outstanding common units, our general partner has the right, but not the obligation, to purchase all of the remaining common units at a price that is not less than the then-current market price of the common units, as calculated pursuant to the terms of our partnership agreement. Upon consummation of this offering, Insight Equity will own an aggregate of approximately % of our outstanding common units. For additional information about this right, please read "The Partnership Agreement—Limited Call Right" beginning on page 199.
Estimated ratio of taxable income to distributions		We estimate that if you own the common units you purchase in this offering through the record date for distributions for the period ending December 31, 2015, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be % or less of the cash distributed to you with respect to that period. For example, if you receive an annual distribution of $ per unit, we estimate that your average allocable federal taxable income per year will be no more than $ per unit. Please read "Material Federal Income Tax Consequences—Tax Consequences of Unit Ownership—Ratio of Taxable Income to Distributions" beginning on page 208.
Material tax consequences		For a discussion of other material federal income tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the U.S., please read "Material Federal Income Tax Consequences." All statements of legal conclusions contained in "Material Federal Income Tax Consequences" beginning on page 205, unless otherwise noted, are the opinion of Latham & Watkins LLP with respect to the matters discussed therein.
Exchange listing		We have applied to list our common units on the New York Stock Exchange under the symbol "EMES."

Summary Historical and Pro Forma Financial and Operating Data

We were formed in April 2012 and do not have historical financial operating results. Upon the consummation of this offering, SSS, AEC and Direct Fuels will be contributed to us and we will own and operate their businesses. SSS and AEC, which together constitute our predecessor for accounting purposes, are, prior to the completion of this offering, under the common control of a private equity fund managed and controlled by Insight Equity and, as a result, their contribution to us will be recorded as a combination of entities under common control, whereby the assets and liabilities sold and contributed are recorded based on their historical carrying value for all periods presented. Direct Fuels is not under common control with SSS and AEC and, as a result, the contribution of Direct Fuels to us will be accounted for as an acquisition, whereby the assets and liabilities sold and contributed are recorded at their fair values on the date of contribution.

The summary historical financial and operating data as of December 31, 2010, 2011 and 2012 and for the years ended December 31, 2010, 2011 and 2012 are derived from the audited historical consolidated financial statements of SSS and AEC included elsewhere in this prospectus.

Our summary pro forma financial and operating data as of December 31, 2012 and for the year ended December 31, 2012 are derived from the unaudited pro forma financial statements of Emerge Energy Services, the unaudited pro forma condensed combined financial statements of our predecessor and the audited historical consolidated financial statements of Direct Fuels included elsewhere in this prospectus. Our unaudited pro forma financial and operating data consist of the combined results of SSS and AEC as if such combination occurred on January 1, 2010 and give effect to the acquisition of Direct Fuels as if such acquisition occurred on December 31, 2012 for pro forma balance sheet purposes and on January 1, 2012 for the purposes of all other pro forma financial statements. We have not given pro forma effect to incremental selling, general and administrative expenses of approximately $3.5 million that we expect to incur annually as the result of being a publicly traded partnership.

You should read the following tables in conjunction with "—Partnership Structure and Offering-Related Transactions" beginning on page 14, "Use of Proceeds" on page 60, "Management's Discussion and Analysis of Financial Condition and Results of Operations" beginning on page 87, and the historical consolidated financial statements and unaudited pro forma condensed combined financial statements and the notes thereto included elsewhere in this prospectus. Among other things, the historical consolidated financial statements and unaudited pro forma financial statements include more detailed information regarding the basis of presentation for the following information.

The following tables present a non-GAAP financial measure, Adjusted EBITDA, which we use in evaluating the financial performance and liquidity of our business. This measure is not calculated or presented in accordance with generally accepted accounting principles, or GAAP. We explain this measure below and reconcile it to its most directly comparable financial measures calculated and presented in accordance with GAAP. For a discussion of how we use Adjusted EBITDA to evaluate our

operating performance, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—How We Evaluate Our Operations" beginning on page 92.

	Predecessor Historical

	Predecessor Historical																		Pro Forma Emerge Energy Services
	SSS									AEC									Pro Forma Emerge Energy Services
	Year Ended December 31,									Year Ended December 31,									Year Ended December 31,
	2010			2011			2012			2010			2011			2012			2012
																			(unaudited)
	(in thousands)
Statements of Operations Data:
Revenues	$	17,131		$	28,179		$	66,697		$	244,476		$	349,309		$	557,399		$	956,863
Operating expenses:
Cost of goods sold(1)		18,211			19,311			27,401			239,072			339,939			548,003			890,573
Selling, general and administrative		6,246			4,995			5,512			3,783			3,973			4,638			13,962
Depreciation, depletion and amortization(2)		2,568			4,022			6,377			3,079			2,858			2,742			11,850
Provision for bad debts		702			—			57			330			—			—			57
Impairment of land		—			762			—			—			—			—			—
Equipment relocation costs		—			572			—			—			—			—			—
(Gain) loss on disposal of equipment		—			364			(33	)		(180	)		(111	)		5			(28	)

Total operating expenses		27,727			30,026			39,314			246,084			346,659			555,388			916,414

Operating income (loss)		(10,596	)		(1,847	)		27,383			(1,608	)		2,650			2,011			40,449

Other expense (income):
Interest expense		980			1,835			10,619			3,892			1,536			813			12,597
Litigation settlement expense		—			—			—			—			—			750			750
Gain on extinguishment of trade payable		—			—			—			—			(1,212	)		—			—
Gain from debt restructuring, net		—			—			—			—			(472	)		—			—
Changes in fair market value of interest rate swap		—			—			—			(281	)		(243	)		—			(46	)
Other expense (income)		—			42			(112	)		(49	)		(99	)		(33	)		(145	)

Total other expense, net		980			1,877			10,507			3,562			(490	)		1,530			13,156

Income (loss) before tax expense		(11,576	)		(3,724	)		16,876			(5,170	)		3,140			481			27,293
Provision for state franchise and margin taxes		36			101			81			(1,051	)		—			—			163

Net income (loss)	$	(11,612	)	$	(3,825	)	$	16,795		$	(4,119	)	$	3,140		$	481		$	27,130

Balance Sheet Data (at period end):
Property, plant and equipment, less accumulated depreciation	$	19,853		$	36,310		$	80,749		$	43,113		$	41,136		$	40,102
Total assets		35,449			59,511			121,498			64,865			68,069			74,289
Total liabilities		65,223			92,877			138,069			61,604			42,483			48,222
Total Partners'/ members' equity		(29,774	)		(33,366	)		(16,571	)		3,261			25,586			26,067
Cash Flow Data:
Net cash provided by (used in):
Operating activities		(1,298	)		2,482			2,201			3,145			(6,088	)		(1,065	)
Investing activities		(1,384	)		(13,912	)		(37,690	)		(152	)		(842	)		(1,384	)
Financing activities		4,465			14,007			31,088			(1,003	)		5,610			1,795
Other Financial Data:
Adjusted EBITDA		(7,326	)		3,873			33,784			1,621			5,397			4,758			52,328
Capital Expenditures
Maintenance(3)		(328	)		(748	)		(1,248	)		(353	)		(226	)		(1,272	)
Growth(4)		(1,056	)		(13,495	)		(37,814	)		—			(710	)		(131	)

Total	$	(8,710	)	$	(10,370	)	$	(5,278	)	$	1,268		$	4,461		$	3,355

(1): Cost of goods sold for AEC Holdings, Direct Fuels and SSS is calculated by adding the cost of fuel or sand, as applicable, and non-capitalized operations and maintenance expense.

(2): The pro forma calculations assume the purchase price for Direct Fuels is estimated to be $111.8 million as of December 31, 2012 and balance sheet accounts have been adjusted to fair value accordingly. The purchase price includes debt funding to redeem $7.4 million of preferred units, the assumption of $17.1 million of current and long-term debt and an equity purchase value of $87.3 million. The purchase price does not include any additional debt that the Partnership may assume.
(3): Maintenance capital expenditures are capital expenditures required to maintain, over the long term, our asset base, operating income or operating capacity. The maintenance capital expenditure amounts set forth above are unaudited.
(4): Growth capital expenditures are capital expenditures made to increase, over the long term, our asset base, operating income or operating capacity. The growth capital expenditure amounts set forth above are unaudited.

	Predecessor Historical

	SSS						AEC
	Predecessor Historical
	Predecessor Historical												Pro Forma Emerge Energy Services
	SSS						AEC						Pro Forma Emerge Energy Services
	Year Ended December 31,						Year Ended December 31,						Year Ended December 31,
	2010		2011		2012		2010		2011		2012		2012
	(unaudited, in thousands except for per unit data)
Operating Data:
Sand segment:
Sand production volume (metric tons)		184.1		382.0		1,222.4		—		—		—		1,222.4
Average price (per ton)(1)	$	93.05	$	73.77	$	54.56		—		—		—	$	54.56
Average production cost (per ton)(2)	$	98.92	$	50.55	$	22.41		—		—		—	$	22.41
Fuel Processing and Distribution segment:
Fuel Distribution (gallons)		—		—		—		102,375		111,172		176,451		284,629
Throughput (gallons)		—		—		—		364,007		358,706		352,585		463,065

(1): Average price (per ton) equals revenues divided by total tons sold. The price per ton of northern Ottawa white frac sand sold from the Kosse facility includes a higher relative freight surcharge to cover the costs of transporting sand from Wisconsin to the Kosse facility. SSS's shift to selling northern Ottawa white frac sand directly from its Wisconsin facilities rather than through its Kosse, Texas facility is reflected in the decreasing average price (per ton) trend.
(2): Average production cost (per ton) equals cost of goods sold divided by total tons sold. Because SSS incurs shipment costs when it transports northern Ottawa white frac sand from Wisconsin to the Kosse facility, SSS's shift to selling northern Ottawa white frac sand directly from its Wisconsin facilities rather than its Kosse, Texas facility is reflected in the decreasing average production cost (per ton) trend.

Non-GAAP Financial Measures

We include in this prospectus the non-GAAP financial measures of Adjusted EBITDA and operating working capital. Our management views Adjusted EBITDA as one of our primary financial metrics, and we track this item on a monthly basis both as an absolute amount and as a percentage of revenues compared to the prior month, year-to-date and prior year and to budget. Similarly, our management uses operating working capital to manage and evaluate, on a real time basis, the performance of certain balance sheet accounts unrelated to our capital structure.

Adjusted EBITDA

•: the financial performance of our assets without regard to the impact of financing methods, capital structure or historical cost basis of our assets;
•: the viability of capital expenditure projects and the overall rates of return on alternative investment opportunities;
•: our liquidity position and the ability of our assets to generate cash sufficient to make debt payments and to make distributions; and
•: our operating performance as compared to those of other companies in our industry without regard to the impact of financing methods and capital structure.

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

reconciliation of Adjusted EBITDA to net income and net cash provided by operating activities, our most directly comparable GAAP measures, for each of the periods indicated:

	Predecessor Historical

	Predecessor Historical																		Pro Forma Emerge Energy Services
	SSS									AEC									Pro Forma Emerge Energy Services
	Year Ended December 31,									Year Ended December 31,									Year Ended December 31,
	2010			2011			2012			2010			2011			2012			2012
																			(unaudited)
	(in thousands)
Reconciliation of Adjusted EBITDA to net income (loss):
Net income (loss)	$	(11,612	)	$	(3,825	)	$	16,795		$	(4,119	)	$	3,140		$	481		$	27,130
Depreciation, depletion and amortization expense(1)		2,568			4,022			6,377			3,079			2,858			2,742			11,850
Income tax expense (benefit)		36			101			81			(1,051	)		—			—			163
Interest expense		980			1,835			10,619			3,892			1,536			813			12,597
Changes in fair value of derivative instruments		—			—			—			(281	)		(243	)		—			(46	)
Litigation settlement expense(2)		—			—			—			—			—			750			750
Gain on extinguishment of trade payable(3)		—			—			—			—			(1,212	)		—			—
Loss (gain) from debt restructuring(4)		—			—			—			—			(472	)		—			—
Other expense (income)		—			42			(112	)		(49	)		(99	)		(33	)		(145	)
Provision for bad debts(5)		702			—			57			330			—			—			57
Impairment of land(6)		—			762			—			—			—			—			—
Equipment relocation costs(7)		—			572			—			—			—			—			—
(Gain) loss on disposal of equipment		—			364			(33	)		(180	)		(111	)		5			(28	)

Adjusted EBITDA	$	(7,326	)	$	3,873		$	33,784		$	1,621		$	5,397		$	4,758		$	52,328

Reconciliation of Adjusted EBITDA to net cash provided by operating activities:
Net cash from (used for) operating activities	$	(1,298	)	$	2,482		$	2,201		$	3,145		$	(6,088	)	$	(1,065	)	$	12,319
Changes in operating assets and liabilities		(5,816	)		(1,210	)		22,580			(4,607	)		10,981			4,576			28,897
Litigation settlement expense(2)		—			—			—			—			—			750			750
Equipment relocation costs(7)		—			572			—			—			—			—			—
Income tax expense (benefit)		36			101			81			—			—			—			163
Interest expense, net		956			1,897			9,720			3,692			1,362			642			11,172
Interest converted to long-term debt(8)		(1,055	)		—			(743	)		(560	)		(759	)		—			(743	)
Write-off of accounts receivable		—			(11	)		57			—			—			—			57
Write-down of inventory		(149	)		—			—			—			—						—
Other expense (income)		—			42			(112	)		(49	)		(99	)		(33	)		(145	)
Provision for doubtful accounts		—			—			—			—			—			(112	)		(142	)

Adjusted EBITDA	$	(7,326	)	$	3,873		$	33,784		$	1,621		$	5,397		$	4,758		$	52,328

(1): The pro forma calculations assume the purchase price for Direct Fuels to be $111.8 million as of December 31, 2012, and balance sheet accounts and related amortization and depreciation have been adjusted to fair value accordingly. The purchase price includes debt funding to redeem $7.4 million of preferred units, the assumption of $17.1 million of current and long-term debt and an equity purchase value of $87.3 million. The purchase price does not include any additional debt that the Partnership may assume.
(2): Reflects AEC's settlement of litigation that alleged environmental damage to property contiguous to its bulk fuel terminal facility. The settlement agreement extinguished all alleged liabilities and included mutual releases between the parties involved.
(3): Reflects AEC's settlement of a dispute with a supplier for less than the amount that had been reserved, which resulted in a gain in the amount of $1.2 million in 2011.
(4): Reflects (a) a gain at AEC of $0.5 million in 2011 resulting from the restructuring of its debt obligations, and a loss of $0.6 million from penalties related to Direct Fuels' prepayment of an outstanding subordinated debt obligation.
(5): Reflects (a) a write-off at SSS in 2010 of a deposit to a supplier in the amount of $0.7 million and (b) a write-off of uncollectible accounts receivable at AEC in 2010 of $0.3 million.
(6): Reflects an impairment charge in 2011 at SSS in the amount of $0.8 million against the carrying value of a non-business generating asset originally acquired as part of the SSS acquisition in 2008 that was sold in 2012.
(7): Reflects the incurrence of costs in the amount of $0.6 million at SSS associated with relocating certain pieces of equipment from its Kosse, Texas facility to its New Auburn, Wisconsin facility in 2011.
(8): Reflects a portion of interest owed by SSS and AEC in 2010, 2011, and 2012 that was added to the outstanding principal amount.

Operating Working Capital

We define operating working capital as the amount by which the sum of accounts receivable, inventory, prepaid expenses and other current assets exceeds the sum of accounts payable, accrued expenses and income taxes payable. Our definition of operating working capital differs from "working capital," as defined by GAAP, primarily because it excludes balance sheet items that are related to the capital structure of the business such as the current portion of long-term debt as well as the current portion of the capitalized lease liabilities. These items are influenced to a large extent by long-term capital structuring decisions, whereas the items included in our definition of operating working capital tend to fluctuate on a monthly basis based on decisions made by management and the operation of the business. As a result, management uses operating working capital when measuring the effectiveness with which these key balance sheet items are being managed on a real-time basis.

The following tables present a reconciliation of operating working capital to net current assets, the most directly comparable GAAP measure, for each of the periods indicated:

	Pro Forma Predecessor SSS and AEC Historical Combined									Historical Direct Fuels									Pro Forma Emerge Energy Services

	Year Ended December 31,									Year Ended December 31,									Year Ended December 31,
	2010			2011			2012			2010			2011			2012			2012
	(unaudited)																		(unaudited)
	(in thousands)
Total current assets	$	22,969		$	36,348		$	55,275		$	24,768		$	23,377		$	25,316		$	80,591
less: Total current liabilities		42,207			31,924			50,533			8,150			12,469			29,564			79,747

Net current assets (liabilities)		(19,238	)		4,424			4,742			16,618			10,908			(4,248	)		844
less: cash and cash equivalents		(5,264	)		(6,521	)		(1,465	)		(992	)		(4,229	)		(2,544	)		(4,009	)
less: lease receivable		—			—			(1,579	)		—			—			—			(1,579	)
less: assets held for sale		—			(1,338	)		—			(6,876	)		—			—			—
plus: deferred revenue		—			—			801			—			—			—			801
plus: current portion of long-term debt		7,158			677			9,322			1,700			1,838			17,067			26,039
plus: current portion of capital lease liability		120			1,990			1,548			—			—			—			1,548
plus: current portion of advances from customers		—			7,968			4,043			—			—			—			4,043
plus: current portion of seller notes and subordinated debt		13,052			—			—			—			—			—			—

Operating working capital	$	(4,172	)	$	7,200		$	17,412		$	10,450		$	8,517		$	10,275		$	27,687

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 prospectus 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.

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 will fluctuate from quarter to quarter based on, among other things:

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

Our partnership agreement will 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, will be determined by the board of directors of our general partner. Our quarterly distributions, if any, will be subject to significant fluctuations based on the above factors.

For a description of additional restrictions and factors that may affect our ability to make cash distributions, please read "Our Cash Distribution Policy and Restrictions on Distributions" beginning on page 66.

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 will be 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 will 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 will 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 will be 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, future quarterly distributions paid to our unitholders may vary significantly from quarter to quarter and may be zero. See "Our Cash Distribution Policy and Restrictions on Distributions" on page 66.

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 will adopt a cash distribution policy pursuant to which we will 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.

The assumptions underlying our estimate of cash available for distribution described in "Our Cash Distribution Policy and Restrictions on Distributions" are inherently uncertain and subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those forecasted.

Our estimate of cash available for distribution for the twelve months ending March 31, 2014 set forth in "Our Cash Distribution Policy and Restrictions on Distributions" beginning on page 66 is based on assumptions that are inherently uncertain and subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those estimated. The estimate was prepared by our management, and we have not received an opinion or report on it from our independent registered public accounting firm or any other independent auditor. If we do not achieve the estimated results, 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. Our actual results may differ materially from the estimated results presented in this prospectus.

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, or OPEC, have contributed, and are likely to continue to contribute, to commodity price volatility. Additionally, warmer than normal winters in North America and other weather patterns may adversely impact the short-term demand for oil and natural gas and, therefore, demand for our products.

During periods of economic slowdown, 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 cause actual results of operations to differ materially from historical and expected results. 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:

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 Processing and Distribution 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 2012, our top five Sand customers represented approximately 92% of sales from our Sand operations. During 2012, our top five Fuel Processing and Distribution customers represented, on a pro forma basis, approximately 52% of sales from our Fuel Processing and Distribution operations. In our Fuel Processing and Distribution 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.

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, Inc., or 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.

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 Processing and Distribution 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 Processing and Distribution 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) 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 nine 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 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 63% of our supply of transmix pursuant to exclusive contracts with terms ranging from 12 to 36 months and a volume-weighted average remaining duration of approximately 17 months as of December 31, 2012. In addition, we have a number of non-exclusive supply contracts that collectively represent approximately 14% of our transmix supply. These contracts have an average remaining duration of approximately four months as of December 31, 2012. For the year ended December 31, 2012, our two largest suppliers of transmix accounted for approximately 41% and 8% of our total transmix purchases. The contract with our largest supplier for the year ended December 31, 2012 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 margins would be adversely affected if a 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. We also expect to engage an industrial mining expert at our Barron County facility when it becomes operational. 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:

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.

We will incur increased costs as a result of being a publicly traded partnership and may be unable to successfully integrate the administration and management of our previously independent operating subsidiaries.

We have no history operating as a publicly traded partnership. We are in the process of hiring additional accounting and financial reporting personnel to assist with bookkeeping and our preparation of periodic financial reports. We may not be successful in attracting additional key accounting personnel, which could have a material adverse effect on our ability to comply with the financial reporting requirements of a publicly traded partnership.

Also, as a publicly traded partnership, we will incur significant legal, accounting and other expenses. In addition, the Sarbanes-Oxley Act of 2002 and related rules subsequently implemented by the SEC and the NYSE have required changes in the corporate governance practices of publicly traded companies. We expect these rules and regulations to increase our legal and financial compliance costs and to make activities more time-consuming and costly. For example, as a result of being a publicly traded partnership, we are required to have at least three independent directors, create an audit committee and adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal controls over financial reporting. In addition, we will incur additional costs associated with our publicly traded partnership reporting requirements. We also expect these new rules and regulations to make it more difficult and more expensive for our general partner to obtain director and officer liability insurance and result in our general partner possibly having to accept reduced policy limits and coverage. As a result, it may be more difficult for our general partner to attract and retain qualified persons to serve on its board of directors or as executive officers. We have included $3.5 million of estimated incremental costs per year associated with being a publicly traded partnership in our financial forecast included elsewhere in this prospectus. However, it is possible that our actual incremental costs of being a publicly traded partnership will be higher than we currently estimate.

In addition, following the completion of this offering, our Sand operations will be conducted through SSS and our Fuel Processing and Distribution operations will be conducted through AEC and Direct Fuels. These three businesses historically have been managed and operated on an independent basis. We may encounter unexpected difficulties in successfully integrating the administration and management of these businesses within our partnership, which could have an adverse impact on our business, financial condition or results of operations.

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 expect to enter into a new $ million revolving credit facility in connection with the closing of this offering, and we expect approximately $ million of borrowings to be outstanding under this facility following the closing of this offering. Following this offering, our ability to incur additional debt will be subject to limitations in our anticipated new revolving credit facility. Our level of debt could have important consequences to us, including the following:

Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be 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 will depend on market interest rates, since we anticipate that the interest rates applicable to our borrowings will 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 anticipated new revolving credit facility may limit our ability to capitalize on acquisition and other business opportunities.

The operating and financial restrictions and covenants in our anticipated new 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, we expect that our revolving credit facility will restrict or limit our ability to:

Furthermore, we expect that our revolving credit facility will contain 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 in our anticipated new revolving credit facility, 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. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Pro Forma Liquidity and Capital Resources—New Revolving Credit Facility" beginning on page 99.

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.

In 2010 and 2011, SSS had, and in 2010 AEC had, material weaknesses in their respective internal control over financial reporting. If one or more material weaknesses persist or if we fail to establish and maintain effective internal control over financial reporting, our ability to accurately report our financial results could be adversely affected.

Upon the consummation of this offering, we will become a publicly traded partnership and will be required to comply with the SEC's rules implementing Sections 302 and 404 of the Sarbanes Oxley Act of 2002, which will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting. Although we will be required to disclose changes made to our internal controls and procedures on a quarterly basis, we will not be required to make our first annual assessment of our internal control over financial reporting pursuant to Section 404 until the year following our first annual report required to be filed with the SEC. To comply with the requirements of being a publicly traded partnership, we will need to implement additional internal controls, reporting systems and procedures and hire additional accounting, finance and legal staff.

Prior to the completion of this offering, we and our predecessors have been private entities with limited accounting personnel and other supervisory resources to execute accounting processes and address internal control over financial reporting. In particular:

A "material weakness" is a deficiency, or combination of deficiencies, in internal controls such that there is a reasonable possibility that a material misstatement in financial statements will not be prevented or detected in a timely basis. The material weakness resulted in several audit adjustments to SSS's consolidated financial statements for the years ended December 31, 2010 and 2011. In addition, during 2011, AEC implemented a number of corrective actions to improve its year-end closing process and inventory costing methodology, and no material weaknesses were identified in connection with the audit of the consolidated financial statements of AEC for the years ended December 31, 2011 and 2012, although there can be no assurances that these remediation steps will continue to be successful. During 2012, SSS implemented corrective actions including hiring additional experienced personnel and implementing stronger closing procedures and no material weaknesses were identified for the year ending December 31, 2012, although there can be no assurances that these remediation steps will continue to be successful. Other than the material weakness as described above, we are not aware of any material weakness in our, our predecessors' or Direct Fuels' internal control over financial reporting. Any material weakness, including those described above, could result in a misstatement of our accounts or disclosures that would result in a material misstatement of our annual or interim combined financial statements that would not be prevented or detected. We cannot assure you that the measures we have taken to date, or any measures we may take in the future, will be sufficient to remediate the material weaknesses described above or avoid potential future material weaknesses.

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

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

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

Our 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 U.S. Environmental Protection Agency, or the EPA, and similar state agencies, have the power to enforce compliance with these laws, regulations and standards and the permits issued under them, often requiring difficult and costly actions.

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

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. Please read "Business—Environmental and Occupational Health and Safety Regulations" beginning on page 157.

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 renewable fuel standard program, or 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 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 point 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 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 April 17, 2012, the EPA issued 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 all 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, or 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 water resulting from hydraulic fracturing by 2014 and the U.S. Department of the Interior, or the DOI, announced 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. 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 the federal Mining Safety and Health Administration and other federal and state agencies relating to workplace exposure to crystalline silica. Our failure to comply with such standards, or changes in such standards or the interpretation or enforcement thereof, could have a material adverse effect on our business and financial condition or otherwise impose significant restrictions on our ability to conduct mineral extraction and processing operations.

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

In addition to the regulatory matters described above, we and our customers are subject to extensive governmental regulation on matters such as permitting and licensing requirements, plant and wildlife threatened and endangered species protection, jurisdictional wetlands protection, reclamation and restoration activities at mining properties after mining is completed, the discharge of materials into

the environment and the effects that mining and hydraulic fracturing have on groundwater quality and availability. Our future success depends, among other things, on the quantity of our frac sand and other mineral deposits and our ability to extract these deposits profitably, and our customers being able to operate their businesses as they currently do.

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

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

The long-term impact of terrorist attacks, such as the attacks that occurred on September 11, 2001, and the magnitude of the threat of future terrorist attacks on the energy industry in general and on us in particular are not known at this time. Uncertainty surrounding hostilities in the Middle East or other sustained military campaigns may affect our operations in unpredictable ways, including disruptions of markets for frac sand and 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.

Pursuant to the recently enacted JOBS Act, our independent registered public accounting firm will not be required to attest to the effectiveness of our internal control over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act of 2002 for as long as we are an emerging growth company, and we may take advantage of an extended transition period for complying with new or revised accounting standards.

For as long as we are an "emerging growth company" under the recently enacted JOBS Act, our independent registered public accounting firm will not be required to attest to the effectiveness of our internal control over financial reporting pursuant to Section 404. We could be an emerging growth company for up to five years. We could cease to be an emerging growth company as early as January 1, 2014, depending on whether we generate more than $1.0 billion in revenues during the fiscal year ending December 31, 2013. See "Summary—Implications of Being an Emerging Growth Company" beginning on page 18. Even if our management concludes that our internal controls over financial reporting are effective, our independent registered public accounting firm may still decline to attest to our management's assessment or may issue a report that is qualified if it is not satisfied with our controls or the level at which our controls are documented, designed, operated or reviewed, or if it interprets the relevant requirements differently from us.

In addition, Section 107 of the JOBS Act also provides that an "emerging growth company" can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act for complying with new or revised accounting standards. In other words, an "emerging growth company" can delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. We are electing to delay such adoption of new or revised accounting standards, and as a result, we may not comply with new or revised accounting standards on the relevant dates on which adoption of such standards is required for non-emerging growth companies. As a result of such election, our financial statements may not be comparable to the financial statements of other public companies. We may take advantage of these reporting exemptions until we are no longer an "emerging growth company." We cannot predict if investors will find our common units less attractive because we will rely on these exemptions. If some investors find our common units less attractive as a result, there may be a less active trading market for our common units and the trading price for our common units may be more volatile.

The board of directors of our general partner will adopt a policy to distribute an amount equal to the available cash we generate each quarter, which could limit our ability to grow and make acquisitions.

The board of directors of our general partner will adopt a policy to distribute an amount equal to the available cash we generate each quarter to our unitholders, beginning with the quarter ending June 30, 2013. As a result, we will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund any acquisitions and expansion capital expenditures. As such, to the extent we are unable to finance growth externally, our distribution policy will significantly impair our ability to grow.

In addition, because of our distribution policy, our growth, if any, may not be as robust as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures or as in-kind distributions, current unitholders will experience dilution and the payment of distributions on those additional units will decrease the amount we distribute on each outstanding unit. 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 additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, would reduce the available cash that we have to distribute to our unitholders. The board of directors of our general partner may change our cash distribution policy at any time at its discretion. Our partnership agreement does not require us to pay distributions to our unitholders on a quarterly or other basis. See "Our Cash Distribution Policy and Restrictions on Distributions" on page 66.

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 will 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 will have 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 will have little ability to remove our general partner. As a result of these limitations, the price at which the common units will trade could 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.

Following this offering, Insight Equity will own the majority of and control our general partner and will appoint all of the officers and directors of our general partner, some of whom will also be 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 will arise between Insight Equity and our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of Insight Equity and the other owners of our general partner over our interests and the interests of our common unitholders. These conflicts include the following situations, among others:

Our general partner intends to limit its liability regarding our obligations.

Our general partner intends to limit 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:

By purchasing a common unit, a common unitholder agrees to become bound by the provisions in the partnership agreement, including the provisions discussed above. Please read "Conflicts of Interest and Duties—Duties of Our General Partner" beginning on page 186.

Even if holders of our common units are dissatisfied, they cannot initially remove our general partner without Insight Equity's consent.

Our unitholders initially will be unable to remove our general partner because our general partner and its affiliates will own sufficient units upon completion of this offering to be able to prevent its removal. The vote of the holders of at least 66²/3% of all outstanding common units voting together as a single class is required to remove our general partner. Following the closing of this offering, Insight Equity will own an aggregate of % of our outstanding common units.

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

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

In connection with a situation involving a transaction with an affiliate or a conflict of interest, any determination by our general partner must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the conflicts committee and the board of directors of our general partner determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest satisfies either of the standards set forth in bullets three and four above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Please read "Conflicts of Interest and Duties—Conflicts of Interest" beginning on page 180.

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.

You will experience immediate and substantial dilution in pro forma net tangible book value of $ per common unit.

The assumed initial public offering price of $ per common unit exceeds our pro forma net tangible book value of $ per common unit. Based on the initial public offering price of $ per common unit, you will incur immediate and substantial dilution of $ per common unit. This dilution results primarily because the assets contributed by our general partner and its affiliates are recorded in accordance with GAAP at their historical carrying value, and not their fair value. Please read "Dilution" beginning on page 64.

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:

Insight Equity may sell units in the public or private markets, and such sales could have an adverse impact on the trading price of the common units.

After the sale of the common units offered by this prospectus, assuming no exercise of the underwriters' option to purchase additional common units, Insight Equity will hold an aggregate of common units. Additionally, we have agreed to provide Insight Equity with certain registration rights. Please read "The Partnership Agreement—Registration Rights" beginning on page 199. The sale of these units in the public or private markets could have an adverse impact on the price of the common units or on any trading market that may develop.

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. At the completion of this offering, and assuming no exercise of the underwriters' option to purchase additional common units, Insight Equity will own an aggregate of approximately % of our outstanding common units. For additional information about this right, please read "The Partnership Agreement—Limited Call Right" beginning on page 199.

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:

For a discussion of the implications of the limitations of liability on a unitholder, please read "The Partnership Agreement—Limited Liability" beginning on page 192.

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 (the "Delaware Act"), we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable both for the obligations of the assignor to make contributions to the partnership that were known to the substituted limited

partner at the time it became a limited partner and for those obligations that were unknown if the liabilities could have been determined from the partnership agreement. Neither liabilities to partners on account of their partnership interest nor liabilities that are non-recourse to the partnership are counted for purposes of determining whether a distribution is permitted.

There is no existing market for our common units, and a trading market that will provide you with adequate liquidity may not develop. The price of our common units may fluctuate significantly, and you could lose all or part of your investment.

Prior to this offering, there has been no public market for our common units. After this offering, there will be only publicly traded common units, assuming no exercise of the underwriters' option to purchase additional common units. In addition, Insight Equity will own an aggregate of common units, representing an aggregate % limited partner interest in us. We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. You may not be able to resell your common units at or above the initial public offering price. Additionally, the lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the common units and limit the number of investors who are able to buy the common units.

The initial public offering price for the common units will be determined by negotiations between us and the representatives of the underwriters and may not be indicative of the market price of the common units that will prevail in the trading market. The market price of our common units may decline below the initial public offering price. The market price of our common units may also be influenced by many factors, some of which are beyond our control, including:

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.

We have applied to list our common units on the on the NYSE. Because we will be 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 will not have the same protections afforded to certain corporations that are subject to all of the NYSE corporate governance requirements. Please read "Management of Emerge Energy Services LP" beginning on page 164.

In addition to reading the following risk factors, please read "Material Federal Income Tax Consequences" beginning on page 205 for a more complete discussion of the expected material federal income tax consequences of owning and disposing of common units.

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

The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter affecting us. 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 are or 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.

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 the existing federal income tax laws that affect publicly traded partnerships. Please read "Material Federal Income Tax Consequences—Partnership Status" beginning on page 206. 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 will be taxable to them for federal income tax purposes even if they do not receive any cash distributions from us.

Because a unitholder will be treated as a partner to whom we will allocate taxable income which could be different in amount than the cash we distribute, a unitholder's allocable share of our taxable income will be 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.

We have not requested a ruling from the IRS 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 conclusions of our counsel expressed in this prospectus or 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 our counsel's conclusions or the positions we take and such positions may not ultimately be sustained. A court may not agree with some or all of our counsel's conclusions or 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.

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 sell your common units, you may incur a tax liability in excess of the amount of cash you receive from the sale. Please read "Material Federal Income Tax Consequences—Disposition of Common Units—Recognition of Gain or Loss" beginning on page 217 for a further discussion of the foregoing.

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, will be unrelated business taxable income and will be taxable to them.

Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be 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 will 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 will adopt 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 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. Please read "Material Federal Income Tax Consequences—Tax Consequences of Unit Ownership—Section 754 Election" beginning on page 212 for a further discussion of the effect of the depreciation and amortization positions we will adopt.

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 will 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. Please read "Material Federal Income Tax Consequences—Disposition of Common Units—Allocations Between Transferors and Transferees" beginning on page 219.

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 deduction 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 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 recently 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 notwithstanding two partnership tax years. Please read "Material Federal Income Tax Consequences—Disposition of Common Units—Constructive Termination" beginning on page 219 for a discussion of the consequences of our termination for federal income tax purposes.

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 will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or control property now or in the future, even if they do not live in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We initially expect to conduct business in Texas, Alabama and Wisconsin. Alabama and Wisconsin currently impose a personal income tax on individuals. 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.

We expect to receive net proceeds of approximately $ million from this offering, after deducting underwriting discounts and commissions and the structuring fee, but before paying offering expenses. Our estimate assumes an initial public offering price of $ per common unit and no exercise of the underwriters' option to purchase additional common units.

We will use the net proceeds from this offering (excluding the net proceeds from any exercise of the underwriters' option to purchase additional common units), together with borrowings under our anticipated new credit facility to:

The following table illustrates our expected use of the proceeds from this offering and borrowings under our anticipated new credit facility (excluding the net proceeds from any exercise of the underwriters' option to purchase additional common units).

Sources of Cash (in millions)		Uses of Cash (in millions)

Net proceeds to us from this offering	$	Aggregate distributions to SSH, AEC Holdings, and DF Parent	$
Borrowings under our anticipated new credit facility		Repayment of SSS debt
		Repayment of AEC Holdings debt
		Repayment of Direct Fuels debt
		Contribution to operating subsidiary
		Payment of cash-based compensation awards
		Offering expenses

Total	$	Total	$

If the underwriters exercise their option to purchase additional common units in full, the additional net proceeds will be approximately $ million. All of the net proceeds from any exercise of such option will be used to make an additional cash distribution to Insight Equity and other private investors. Any remaining common units not purchased by the underwriters pursuant to any exercise of the option will be issued to Insight Equity and the other private investors at the expiration of the option period, and we will not receive additional consideration from them for the issuance to them of these units. Any exercise of the underwriters' option will not affect the total number of units outstanding. Please read "Underwriting" beginning on page 228.

Immediately following the repayment of the outstanding balance of SSS's, AEC Holdings' and Direct Fuels' existing debt with the net proceeds of this offering, we will enter into a new revolving

credit facility and borrow approximately $ million under that revolving credit facility. We will use the proceeds from these borrowings to (i) make distributions of $ million, $ million and $ million to SSH, AEC Holdings and DF Parent, respectively, and (ii) pay fees and expenses of approximately $ million relating to our anticipated new revolving credit facility. We expect borrowings under our new revolving credit facility to initially bear interest at approximately %. We expect that our new revolving credit facility will mature years from the closing date of this offering.

As of , 2013 there was an aggregate $ million outstanding under our credit facilities. For additional information regarding existing debt arrangements, please see "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Arrangements."

An increase or decrease in the initial public offering price of $1.00 per common unit would cause the net proceeds from the offering, after deducting underwriting discounts and commissions and the structuring fee, to increase or decrease, respectively, by $ million. In addition, we may also increase or decrease the number of common units we are offering. Each increase of 1.0 million common units offered by us, together with a concurrent $1.00 increase in the assumed public offering price of $ per common unit, would increase net proceeds to us from this offering by approximately $ million. Similarly, each decrease of 1.0 million common units offered by us, together with a concurrent $1.00 decrease in the assumed initial offering price of $ per common unit, would decrease the net proceeds to us from this offering by approximately $ million. Any increase or

decrease in the net proceeds to us from this offering will result in a corresponding adjustment to the distribution to SSH, AEC Holdings and DF Parent described in the first bullet point above.

An affiliate of Citigroup Global Markets Inc. is a lender under AEC Holdings' credit facility and will receive a portion of the net proceeds from this offering, and in addition, another affiliate of Citigroup Global Markets Inc. owns an approximate 4.4% interest in AEC Holdings. An affilliate of Wells Fargo Securities, LLC is a lender under SSH's credit facility and will receive a portion of the net proceeds from this offering. An affiliate of Stifel, Nicolaus & Company, Incorporated is also a lender under SSH's credit facility and will receive a portion of the net proceeds from this offering. See "Underwriting" beginning on page 228.

We derived this table from, and it should be read in conjunction with and is qualified in its entirety by reference to, the unaudited pro forma condensed combined financial statements included elsewhere in this prospectus. You should also read this table in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" beginning on page 87.

The pro forma as adjusted information set forth above is illustrative only and following the completion of this offering will be adjusted based on the actual initial public offering price and other terms of this offering determined at pricing. Please read "Use of Proceeds—Sensitivity in Offering Size" beginning on page 61.

Dilution is the amount by which the offering price paid by the purchasers of common units sold in this offering will exceed the pro forma net tangible book value per unit after the offering. On a pro forma basis as of December 31, 2012, after giving effect to the offering of common units and the application of the related net proceeds, and assuming the underwriters' option to purchase additional common units is not exercised, our net tangible book value was $ million, or $ per unit. Purchasers of common units in this offering will experience substantial and immediate dilution in net tangible book value per common unit for financial accounting purposes, as illustrated in the following table:

The following table sets forth the number of units that we will issue and the total consideration contributed to us by our general partner and its affiliates and by the purchasers of common units in this offering upon consummation of the transactions contemplated by this prospectus:

You should read the following discussion of our cash distribution policy in conjunction with the factors and assumptions upon which our cash distribution policy is based, which are included under the heading "—Assumptions and General Considerations" below. In addition, please read "Forward Looking Statements" beginning on page 233 and "Risk Factors" beginning on page 29 for information regarding statements that do not relate strictly to historical or current facts and certain risks inherent in our business. For additional information regarding our historical and pro forma operating results, you should refer to our historical consolidated financial statements and pro forma financial data, and the notes thereto, included elsewhere in this prospectus.

Our Cash Distribution Policy. The board of directors of our general partner will adopt a policy pursuant to which we will distribute all of the available cash we generate each quarter, to unitholders of record on the applicable record date, beginning with the quarter ending June 30, 2013. Available cash for each quarter will be determined by the board of directors of our general partner following the end of such quarter. We expect that available cash for each quarter will generally equal our cash flow from operations for the quarter, less cash needed for maintenance capital expenditures, debt service and other contractual obligations, and reserves for future operating or capital needs that the board of directors of our general partner deems necessary or appropriate. We do not intend to maintain excess distribution coverage for the purpose of maintaining stability or growth in our quarterly distribution or otherwise to reserve cash for distributions, nor do we intend to incur debt to pay quarterly distributions. We expect to finance substantially all of our growth externally, either by debt issuances or additional issuances of equity. We expect to fund capital expenditures with cash reserves and borrowings under our credit facility.

Because our policy will be to distribute all available cash we generate each quarter, without reserving cash for future distributions or borrowing to pay distributions during periods of low cash flow from operations, our unitholders will have direct exposure to fluctuations in the amount of cash generated by our business. We expect that the amount of our quarterly cash distributions, if any, may not be stable and may vary from quarter to quarter as a direct result of variations in our operating performance and cash flow, which will be affected by product price fluctuations and demand trends as well as our working capital requirements and capital expenditures. Such variations may be significant. The board of directors of our general partner may change the foregoing distribution policy at any time and from time to time. Our partnership agreement does not require us to pay cash distributions on a quarterly or other basis.

Limitations on Cash Distributions; Our Ability to Change Our Cash Distribution Policy. There is no guarantee that unitholders will receive quarterly cash distributions from us. Our distribution policy may be changed at any time and is subject to certain restrictions, including:

We do not have any operating history as an independent company upon which to rely in evaluating whether we will have sufficient cash to allow us to pay distributions on our common units. While we believe, based on our financial forecast and related assumptions, that we should have sufficient cash to enable us to pay the forecasted aggregate distribution on all of our common units for the twelve months ending March 31, 2014, we may be unable to pay the forecasted distribution or any amount on our common units.

We expect to pay our distributions within sixty days of the end of each quarter. Our first distribution will include available cash for the period from the closing of this offering through the quarter ending June 30, 2013.

Unaudited Pro Forma Cash Available for Distribution for the Year Ended December 31, 2012

If we had completed the transactions contemplated in this prospectus on January 1, 2012, our pro forma cash available for distribution for the year ended December 31, 2012 would have been approximately $34.6 million. Based on the cash distribution policy we expect our board of directors to adopt, this amount would have resulted in an annual distribution equal to $ per common unit for the year ended December 31, 2012. References in this section to our pro forma cash available for distribution refer to our pro forma results of operations for the year ended December 31, 2012, which consist of the combined results of SSS and AEC as if such combination occurred on January 1, 2010 and give effect to the acquisition of Direct Fuels as if such acquisition occurred on January 1, 2012.

Our unaudited pro forma cash available for distribution for the year ended December 31, 2012 gives effect to $3.5 million of incremental annual general and administrative expenses that we expect to incur as a result of becoming a publicly traded partnership. This amount is an estimate, and our general partner will ultimately determine the actual amount of these incremental annual general and administrative expenses to be reimbursed by us in accordance with our partnership agreement. Incremental annual general and administrative expenses related to being a publicly traded partnership include expenses associated with annual and quarterly SEC reporting; tax return and Schedule K-1 preparation and distribution expenses; Sarbanes-Oxley compliance expenses; expenses associated with listing on the NYSE; independent auditor fees; legal fees; investor relations expenses; registrar and transfer agent fees; director and officer liability insurance costs and outside director compensation. These expenses are not reflected in our predecessors' historical consolidated financial statements or in the pro forma financial statements included elsewhere in this prospectus.

The pro forma financial statements, upon which pro forma cash available for distribution is based, do not purport to present our results of operations had the transactions contemplated in this prospectus actually been completed as of the dates indicated. Furthermore, cash available for distribution is a cash accounting concept, while our pro forma financial statements have been prepared on an accrual basis. We derived the amounts of pro forma cash available for distribution shown above in the manner described in the table below. As a result, the amount of pro forma cash available for distribution should only be viewed as a general indication of the amount of cash available for distribution that we might have generated had we been formed and completed the transactions contemplated in this prospectus in earlier periods. Please see our unaudited pro forma condensed combined financial statements included elsewhere in this prospectus.

The following table illustrates, on a pro forma basis, for the year ended December 31, 2012, the amount of available cash (without any reserve) that would have been available for distribution to our unitholders, assuming that the offering had been consummated on January 1, 2012. Each of the adjustments is explained in further detail in the footnotes to such adjustments. Unaudited pro forma cash available for distribution for the year ended December 31, 2012 was derived from the unaudited pro forma condensed combined financial statements included elsewhere in this prospectus.

	Year Ended December 31, 2012

	(in millions, except per unit data)
Pro Forma Net Income	$	27.1
Add:
Provision for state franchise/margin taxes		0.2
Interest expense		12.6
Other expense (income)(1)		0.6
Depreciation, depletion and amortization expense		11.8

Pro Forma Adjusted EBITDA	$	52.3
Less:
Incremental annual general and administrative expenses of being a publicly traded partnership(2)		3.5
Cash interest expense(3)		11.2
Customer advance liability payments(4)		10.1
Capitalized lease principal payments(5)		1.4
Maintenance capital expenditures(6)		3.0
Growth capital expenditures(7)		38.8
Add:
Borrowings to offset customer advance liability payments(4)		10.1
Borrowings to offset capitalized lease principal payments(5)		1.4
Borrowings to fund growth capital expenditures		38.8

Pro Forma Cash Available for Distribution by Emerge Energy Services LP	$	34.6

Common units outstanding
Pro forma cash available for distribution per unit	$

Estimated Cash Available for Distribution for the Twelve Months Ending March 31, 2014

We forecast that our estimated cash available for distribution for the twelve months ending March 31, 2014 will be approximately $65.6 million. We can give you no assurance that our assumptions will be realized or that we will generate any available cash, in which event we will not be able to pay quarterly cash distributions on our common units.

We have not historically made public projections as to future operations, earnings or other results of our business. However, our management has prepared the forecast of estimated cash available for distribution and related assumptions set forth below to present our expectations regarding our ability to generate approximately $65.6 million of cash available for distribution for the twelve months ending March 31, 2014. For additional context, the discussion of our forecasted results for the twelve months ending March 31, 2014 includes a comparison with our pro forma results for the year ended December 31, 2012, which are derived from our pro forma unaudited condensed combined financial statements included elsewhere in this prospectus.

This forecast is a forward-looking statement and should be read together with the historical consolidated and pro forma unaudited condensed financial statements and the accompanying notes included elsewhere in this prospectus and "Management's Discussion and Analysis of Financial Condition and Results of Operations." The accompanying prospective financial information was not prepared with a view toward complying with the published guidelines of the SEC or guidelines established by the American Institute of Certified Public Accountants with respect to prospective financial information, but, in the view of our management, was prepared on a reasonable basis, reflects the best currently available estimates and judgments, and presents, to the best of management's knowledge and belief, the expected course of action and our expected future financial performance. However, this information is not fact and should not be relied upon as being necessarily indicative of future results, and readers of this prospectus are cautioned not to place undue reliance on the prospective financial information. Please read "Forward Looking Statements" beginning on page 233.

The prospective financial information included in this prospectus has been prepared by, and is the responsibility of, our management. Neither our independent registered public accounting firm, nor any other independent accountants have compiled, examined, or performed any procedures with respect to the prospective financial information contained herein, nor have they expressed any opinion or any other form of assurance on such information or its achievability, and assume no responsibility for, and disclaim any association with, the prospective financial information. The reports of our independent registered public accounting firm included in this prospectus relate to our predecessor's and Direct Fuels' historical financial statements, and those reports do not extend to the prospective financial information and should not be read to do so.

When considering our financial forecast, you should keep in mind the risk factors and other cautionary statements under "Risk Factors." The assumptions and estimates underlying the forecast are inherently uncertain and, although we consider them reasonable as of the date of this prospectus, are subject to a wide variety of significant business, economic and competitive risks and uncertainties that could cause actual results to differ materially from those contained in the forecast, including, among others, risks and uncertainties contained in "Risk Factors." These uncertainties and risks may be greater with respect to forecasts on a quarterly basis. Accordingly, there can be no assurance that the forecast is indicative of our future performance or that actual results will not differ materially from those presented in the forecast.

We do not undertake any obligation to release publicly the results of any future revisions we may make to the financial forecast or to update this financial forecast to reflect events or circumstances after the date of this prospectus. In light of this, the statement that we believe that we will have sufficient available cash to allow us to pay the forecasted quarterly distributions to all of our unitholders for the twelve months ending March 31, 2014, should not be regarded as a representation by us, the underwriters or any other person that we will make such distribution. Therefore, you are cautioned not to place undue reliance on this information.

	Three Months Ending												Twelve Months Ending March 31, 2014

	June 30, 2013			September 30, 2013			December 31, 2013			March 31, 2014			Twelve Months Ending March 31, 2014
	(in millions)
Statement of Income Data:
Revenues	$	254.1		$	254.8		$	258.6		$	258.9		$	1,026.4
Operating expenses:
Cost of goods sold(1)		232.5			231.6			235.6			233.6			933.3
Selling, general and administrative(2)		4.5			4.4			4.4			4.9			18.2
Cash-based compensation awards(3)		9.5			—			—			—			9.5
Depreciation, depletion and amortization		4.5			4.5			4.5			4.5			18.0

Total operating expenses		251.0			240.5			244.5			243.0			979.0

Operating income (loss)		3.1			14.3			14.1			15.9			47.4
Interest expense		(1.7	)		(1.8	)		(1.8	)		(1.4	)		(6.7	)
Provision for state franchise/margin taxes		—			—			—			(0.1	)		(0.1	)

Net Income (loss)	$	1.4		$	12.5		$	12.3		$	14.4		$	40.6

Plus:
Interest expense		1.7			1.8			1.8			1.4			6.7
Provision for state franchise/margin taxes		—			—			—			0.1			0.1
Depreciation, depletion and amortization		4.5			4.5			4.5			4.5			18.0

Estimated Adjusted EBITDA	$	7.6		$	18.8		$	18.6		$	20.4		$	65.4

Less:
Interest expense		(1.7	)		(1.8	)		(1.8	)		(1.4	)		(6.7	)
Customer advance liability payments(4)		(1.4	)		—			—			—			(1.4	)
Capitalized lease principal payments(5)		(0.3	)		(0.8	)		(0.7	)		(0.7	)		(2.5	)
Maintenance capital expenditures(6)		(0.7	)		(0.6	)		(0.6	)		(0.7	)		(2.6	)
Growth capital expenditures(7)		(3.1	)		(0.3	)		(0.3	)		(0.2	)		(3.9	)
Add:
Proceeds retained from this offering to fund cash-based compensation awards(3)		9.5			—			—			—			9.5
Borrowings to offset customer advance liability payments(4)		1.4			—			—			—			1.4
Borrowings to offset capitalized lease principal payments(5)		0.3			0.8			0.7			0.7			2.5
Available cash and borrowings to fund growth capital expenditures(7)		3.1			0.3			0.3			0.2			3.9

Estimated Cash Available for Distribution	$	14.7		$	16.4		$	16.2		$	18.3		$	65.6

Common units outstanding
Estimated cash available for distribution per unit	$			$			$			$			$

(1): Cost of goods sold is calculated by adding the cost of fuel or sand, as applicable, and non-capitalized operations and maintenance expense.
(2): Includes $3.5 million of estimated incremental annual cash expense associated with being a publicly traded partnership, such as expenses associated with annual and quarterly SEC reporting; tax return and Schedule K-1 preparation and distribution expenses; Sarbanes-Oxley compliance expenses; expenses associated with listing on the NYSE; independent auditor fees; legal fees; investor relations expenses; registrar and transfer agent fees; director and officer insurance liability costs, and director compensation.
(3): In connection with the closing of this offering, approximately $9.5 million of cash compensation will become payable to certain members of the management of our subsidiaries. We will make a cash payment to our management using a portion of the net proceeds of this offering.
(4): Certain customers prepaid for future sand deliveries to fund a portion of the New Auburn facility construction costs. As we sell product to these customers, the cash we receive is less than the revenues recognized, with the difference treated as a reduction of customer advances. Because this portion of our revenues is non-cash, we have deducted the customer advance liability payments from our Adjusted EBITDA in computing our cash available for distribution. We expect these obligations to be fully satisfied by the end of the calendar year 2013 and have assumed that we will borrow amounts equivalent to such expected non-cash revenues during each quarter of the forecast period. Accordingly, we have added back such borrowed amounts to determine our estimated cash available for distribution for the forecast period.

While the assumptions described in this prospectus are not all-inclusive, the assumptions listed below are those that we believe are significant to our forecasted results of operations, and any assumptions not discussed below were not deemed significant. We believe our actual results of operations will approximate those reflected in our forecast, but we can give no assurance that our forecasted results, including the anticipated commencement dates of our growth projects, will be achieved.

While we believe that these assumptions are reasonable in light of our management's current expectations concerning future events, the estimates underlying these assumptions are inherently uncertain and are subject to significant business, economic, regulatory, environmental and competitive risks and uncertainties that could cause actual results to differ materially from those we anticipate. If our assumptions are not correct, the amount of actual cash available to pay distributions could be substantially less than the amount we currently estimate and could, therefore, be insufficient to allow us to pay the forecasted cash distribution, or any amount, on our outstanding common units, in which event the market price of our common units may decline substantially. When reading this section, you should keep in mind the risk factors and other cautionary statements under the headings "Risk Factors" and "Cautionary Note Regarding Forward-Looking Statements." Any of the risks discussed in this prospectus could cause our actual results to vary significantly from our estimates.

Based on a number of specific assumptions, we believe that, following completion of this offering, we will generate available cash in an amount sufficient to allow us to pay $ per common unit on all of our outstanding units for the twelve months ending March 31, 2014. We believe that our assumptions, which include the following, are reasonable:

Commencement of Operations at Our Barron County Facility. In order to accommodate increasing demand for our northern Ottawa white frac sand, we have acquired the mineral rights to five adjacent mineral deposits in Barron County, Wisconsin that together account for 262 acres and that contain approximately 22.0 million tons of proven recoverable sand reserves, based on the report of our third-party independent mining engineers. Our Barron County facility was constructed to consist of a wet plant with the capacity to process 1.2 million tons of wet sand per year and a dry plant with the capacity to process 2.4 million tons of dry sand per year in gradations of 16/30, 20/40, 30/50, 40/70 and 100 mesh. Both plants were completed in December 2012 and are fully operational. We expect to begin construction of a second wet plant at the Barron facility in the first half of 2014, which we expect will have the capacity to process up to 1.2 million tons of wet sand per year when completed.

Revenues. We estimate that our total revenues for the twelve months ending March 31, 2014 will be approximately $1,026.4 million, compared to our pro forma total revenues of approximately $956.9 million for the year ended December 31, 2012. Our forecast of total revenues is based on the following assumptions:

Cost of Goods Sold. We estimate that our total cost of goods sold for the twelve months ending March 31, 2014 will be approximately $933.3 million, compared to our pro forma cost of goods sold of approximately $890.6 million for the year ended December 31, 2012. Our forecast of costs of goods sold is based on the following assumptions:

Selling, General and Administrative. We estimate that our selling, general and administrative expenses will be $18.2 million for the twelve months ending March 31, 2014, compared to our pro forma selling, general and administrative expense of $14.0 million for the year ended December 31, 2012. This increase includes the $3.5 million of incremental selling, general and administrative expenses that we expect to incur annually as the result of being a publicly traded partnership but which has not been allocated between our Sand and Fuel Processing and Distribution segments. Our estimate does not include any amounts for potential cash-based compensation awards pursuant to our 2012 Long-Term Incentive Plan. Our forecast of selling, general and administrative expense is based on the following assumptions:

Cash-Based Compensation Awards. In connection with the closing of this offering, approximately $9.5 million of cash compensation will become payable to certain members of the management of our subsidiaries. We will make a cash payment to our management upon closing of this offering using a portion of the net proceeds of this offering.

Depreciation, Depletion and Amortization. We estimate that our depreciation, depletion and amortization expenses will be $18.0 million for the twelve months ending March 31, 2014, compared to

our pro forma depreciation, depletion and amortization of $11.9 million for the year ended December 31, 2012. Our forecast of depreciation, depletion and amortization is based on the following assumptions:

Financing. We estimate that our interest expense will be $6.7 million for the twelve months ending March 31, 2014, compared to our pro forma interest expense of $12.6 million for the year ended December 31, 2012. We expect interest expense to decrease due to a reduction in the average borrowings to $107.9 million during the forecast period compared to $166.7 million for the year ended December 31, 2012. Prior to the offering, Direct Fuels will have borrowed $7.4 million to fund the redemption of preferred units. In addition, during the forecast period, additional borrowings will fund principal and imputed interest payments on our capital lease with Fred Weber. We expect to make additional borrowings during the forecast period equivalent to the non-cash revenue associated with customer prepayments.

Capital Expenditures. We estimate that our capital expenditures will be $6.5 million for the twelve months ending March 31, 2014, compared to our pro forma capital expenditures of $41.8 million for the year ended December 31, 2012. Our forecast of capital expenditures is based on the following assumptions:

General Assumptions. Our forecast for the twelve months ending March 31, 2014 is based on the following significant assumptions related to regulatory, industry and economic factors:

While we believe that our assumptions supporting our estimated Adjusted EBITDA and cash available for distribution for the twelve months ending March 31, 2014 are reasonable in light of management's current beliefs concerning future events, the assumptions are inherently uncertain and are subject to significant business, economic, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those we anticipate. Such forward-looking statements are based on assumptions and beliefs that our management believes to be reasonable; however, assumed facts almost always vary from actual results, and the differences between assumed facts and actual results can be material, depending upon the circumstances. Where we express an expectation or belief as to future results, that expectation or belief is expressed in good faith and based on assumptions believed to have a reasonable basis. It cannot be assured, however, that the stated expectation or belief will occur or be achieved or accomplished. If our assumptions are not realized, the actual Adjusted EBITDA and cash available for distribution that we generate could be substantially less than that currently expected and could, therefore, be insufficient to permit us to make the full forecasted quarterly distributions on all of our units for the twelve months ending March 31, 2014, in which event the market price of our common units may decline materially. Please read "Risk Factors" beginning on page 29 and "Forward Looking Statements" beginning on page 233.

Set forth below is a summary of the significant provisions of our partnership agreement that relate to cash distributions.

General. Within 60 days after the end of each quarter, beginning with the quarter ending June 30, 2013, we expect to make distributions, as determined by the board of directors of our general partner, to unitholders of record on the applicable record date.

Common Units Eligible for Distributions. Upon closing of this offering, we will have common units outstanding. Each common unit will be allocated a portion of our income, gain, loss deduction and credit on a pro forma basis and each common unit will be entitled to receive distributions (including upon liquidation) in the same manner as each other unit.

Method of Distributions. We will distribute available cash to our unitholders, pro rata; provided, however, that our partnership agreement allows us to issue an unlimited number of additional equity interests of equal or senior rank. Our partnership agreement permits us to borrow to make distributions, but we are not required and do not intend to borrow to pay quarterly distributions. Accordingly, there is no guarantee that we will pay any distribution on the units in any quarter.

We do not have a legal obligation to pay distributions, and the amount of distributions paid under our policy and the decision to make any distribution is determined by the board of directors of our general partner. Moreover, we may be restricted from paying distributions of available cash by the instruments governing our indebtedness. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources."

General Partner Interest. Upon the closing of this offering, our general partner will own a non-economic general partner interest and therefore will not be entitled to receive cash distributions. However, it may acquire common units and other equity interests in the future, and will be entitled to receive pro rata distributions therefrom.

We were formed in April 2012 and do not have historical financial operating results. Upon the consummation of this offering, SSS, AEC and Direct Fuels will be contributed to us and we will own and operate their businesses. SSS and AEC, which together constitute our predecessor for accounting purposes, are, prior to completion of this offering, under the common control of a private equity fund managed and controlled by Insight Equity and, as a result, their contribution to us will be recorded as a combination of entities under common control, whereby the assets and liabilities sold and contributed are recorded based on their historical carrying value for all periods presented. Direct Fuels is not under common control with SSS and AEC and, as a result, the contribution of Direct Fuels to us will be accounted for as an acquisition, whereby the assets and liabilities sold and contributed are recorded at their fair values on the date of contribution.

The selected historical financial and operating data as of December 31, 2010, 2011, and 2012 and for the years then ended are derived from the audited historical consolidated financial statements of SSS and AEC included elsewhere in this prospectus.

Our selected pro forma financial and operating data as of December 31, 2012 and for the year ended December 31, 2012 are derived from the unaudited pro forma financial statements of Emerge Energy Services, the unaudited pro forma condensed combined financial statements of our predecessor and the audited historical consolidated financial statements of Direct Fuels included elsewhere in this prospectus. Our unaudited pro forma financial and operating data consist of the combined results of SSS and AEC as if such combination occurred on January 1, 2010 and give effect to the acquisition of Direct Fuels as if such acquisition occurred on December 31, 2012 for pro forma balance sheet purposes and on January 1, 2012 for the purposes of all other pro forma financial statements. We have not given pro forma effect to incremental selling, general and administrative expenses of approximately $3.5 million that we expect to incur annually as the result of being a publicly traded partnership.

You should read the following tables in conjunction with "Summary—Partnership Structure and Offering-Related Transactions" beginning on page 14, "Use of Proceeds" on page 60, "Management's Discussion and Analysis of Financial Condition and Results of Operations" beginning on page 87, and the historical consolidated financial statements and unaudited pro forma condensed combined financial statements and the notes thereto included elsewhere in this prospectus. Among other things, the historical consolidated financial statements and unaudited pro forma financial statements include more detailed information regarding the basis of presentation for the following information.

The following tables present a non-GAAP financial measure, Adjusted EBITDA, which we use in evaluating the financial performance and liquidity of our business. This measure is not calculated or presented in accordance with GAAP. We explain this measure below and reconcile it to its most directly comparable financial measures calculated and presented in accordance with GAAP. For a discussion of how we use Adjusted EBITDA to evaluate our operating performance, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—How We Evaluate Our Operations" beginning on page 92.

	Predecessor Historical

	SSS									AEC
	Year Ended December 31,									Year Ended December 31,
	2010			2011			2012			2010			2011			2012
	(in thousands)
Statements of Operations Data:
Revenues	$	17,131		$	28,179		$	66,697		$	244,476		$	349,309		$	557,399
Operating expenses:
Cost of goods sold(1)		18,211			19,311			27,401			239,072			339,939			548,003
Selling, general and administrative		6,246			4,995			5,512			3,783			3,973			4,638
Depreciation, depletion and amortization		2,568			4,022			6,377			3,079			2,858			2,742
Provision for bad debts		702			—			57			330			—			—
Impairment of land		—			762			—			—			—			—
Equipment relocation costs		—			572			—			—			—			—
(Gain) loss on disposal of equipment		—			364			(33	)		(180	)		(111	)		5

Total operating expenses		27,727			30,026			39,314			246,084			346,659			555,388

Operating income (loss)		(10,596	)		(1,847	)		27,383			(1,608	)		2,650			2,011

Other expense (income):
Interest expense		980			1,835			10,619			3,892			1,536			813
Litigation settlement expense		—			—			—			—			—			750
Gain on extinguishment of trade payable		—			—			—			—			(1,212	)		—
Gain from debt restructuring, net		—			—			—			—			(472	)		—
Changes in fair market value of interest rate swap		—			—			—			(281	)		(243	)		—
Other expense (income)		—			42			(112	)		(49	)		(99	)		(33	)

Total other expense, net		980			1,877			10,507			3,562			(490	)		1,530

Income (loss) before tax expense		(11,576	)		(3,724	)		16,876			(5,170	)		3,140			481
Provision for state franchise and margin taxes		36			101			81			(1,051	)		—			—

Net income (loss)	$	(11,612	)	$	(3,825	)	$	16,795		$	(4,119	)	$	3,140		$	481

Balance Sheet Data (at period end):
Property, plant and equipment, less accumulated depreciation	$	19,853		$	36,310		$	80,749		$	43,113		$	41,136		$	40,102
Total assets		35,449			59,511			121,498			64,865			68,069			74,289
Total liabilities		65,223			92,877			138,069			61,604			42,483			48,222
Total Partners'/ members' equity		(29,774	)		(33,366	)		(16,571	)		3,261			25,586			26,067
Cash Flow Data:
Net cash provided by (used in):
Operating activities		(1,298	)		2,482			2,201			3,145			(6,088	)		(1,065	)
Investing activities		(1,384	)		(13,912	)		(37,690	)		(152	)		(842	)		(1,384	)
Financing activities		4,465			14,007			31,088			(1,003	)		5,610			1,795
Other Financial Data:
Adjusted EBITDA		(7,326	)		3,873			33,784			1,621			5,397			4,758
Capital Expenditures
Maintenance(2)		(328	)		(748	)		(1,248	)		(353	)		(226	)		(1,272	)
Growth(3)		(1,056	)		(13,495	)		(37,814	)		—			(710	)		(131	)

Total	$	(8,710	)	$	(10,370	)	$	(5,278	)	$	1,268		$	4,461		$	3,355

	Pro Forma Predecessor SSS and AEC Historical Combined									Historical Direct Fuels									Pro Forma Emerge Energy Services

	Year Ended December 31,									Year Ended December 31,									Year Ended December 31,
	2010			2011			2012			2010			2011			2012			2012
																			(unaudited)
	(in thousands)
Statements of Operations Data:
Revenues	$	261,607		$	377,488		$	624,096		$	225,249		$	261,557		$	332,767		$	956,863
Operating expenses:
Cost of goods sold(1)		257,283			359,250			575,404			215,907			239,886			315,169			890,573
Selling, general and administrative		10,029			8,968			10,150			4,066			4,509			3,812			13,962
Depreciation, depletion and amortization(2)		5,647			6,880			9,119			964			959			1,032			11,850
Provision for bad debts		1,032			—			57			—			—			—			57
Impairment of land		—			762			—			—			—			—			—
Equipment relocation costs		—			572			—			—			—			—			—
(Gain) loss disposal of equipment		(180	)		253			(28	)		—			—			—			(28	)

Total operating expenses		273,811			376,685			594,702			220,937			245,354			320,013			916,414

Operating income (loss)		(12,204	)		803			29,394			4,312			16,203			12,754			40,449

Other expense (income):
Interest expense		4,872			3,371			11,432			3,166			1,365			1,165			12,597
Litigation settlement		—			—			750			—			—			—			750
Gain on extinguishment of trade payable		—			(1,212	)		—			1,779			—			—			—
Loss (gain) from debt restructuring		—			(472	)		—			—			583			—			—
Changes in fair market value of interest rate swap		(281	)		(243	)		—			(97	)		80			(46	)		(46	)
Other expense (income)		(49	)		(57	)		(145	)		—			—			—			(145	)

Total other expense, net		4,542			1,387			12,037			4,848			2,028			1,119			13,156

Income (loss) before tax expense		(16,746	)		(584	)		17,357			(536	)		14,175			11,635			27,293
Provision for state franchise and margin taxes		(1,015	)		101			81			30			220			82			163

Income (loss) from continuing operations		(15,731	)		(685	)		17,276			(566	)		13,955			11,553			27,130

Income from discontinued operations		—			—			—			1,814			1,569			—			—
Gain (loss) on sale of discontinued operations		—			—			—			9,596			(70	)		—			—

Net income (loss)	$	(15,731	)	$	(685	)	$	17,276		$	10,844		$	15,454		$	11,553		$	27,130

Balance Sheet Data (at period end):
Property, plant and equipment, less accumulated depreciation	$	62,966		$	77,446		$	120,851		$	8,837		$	8,423		$	8,743
Total assets		100,314			127,580			195,787			34,286			32,484			35,426
Total liabilities		126,827			135,360			186,291			31,513			20,507			29,564
Total partners'/ members' equity		(26,513	)		(7,780	)		9,496			2,773			11,977			5,862
Cash Flow Data:
Net cash provided by (used in)
Operating activities		1,847			(3,606	)		1,136			(1,464	)		19,200			11,183
Investing activities		(1,536	)		(14,754	)		(39,074	)		15,748			6,433			(1,353	)
Financing activities		3,462			19,617			32,883			(14,496	)		(22,396	)		(11,516	)
Other Financial Data:
Adjusted EBITDA		(5,705	)		9,270			38,542			5,276			17,162			13,786			52,328
Capital Expenditures:
Maintenance(3)		(681	)		(974	)		(2,520	)		(184	)		(336	)		(458	)
Growth(4)		(1,056	)		(14,205	)		(37,945	)		(68	)		(231	)		(895	)

Total	$	(7,442	)	$	(5,909	)	$	(1,923	)	$	5,024		$	16,595		$	12,433

We include in this prospectus the non-GAAP financial measures of Adjusted EBITDA and operating working capital. Our management views Adjusted EBITDA as one of our primary financial metrics, and we track this item on a monthly basis both as an absolute amount and as a percentage of revenues compared to the prior month, year-to-date and prior year and to budget. Similarly, our management uses operating working capital to manage and evaluate the performance of certain non-capital structure balance sheet accounts on a real-time basis.

Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP. Moreover, our Adjusted EBITDA as presented may not be comparable to similarly titled measures of other companies. The following tables present a reconciliation of Adjusted EBITDA to net income and net cash provided by operating activities, our most directly comparable GAAP measures, for each of the periods indicated:

	Predecessor Historical

	SSS									AEC
	Year Ended December 31,									Year Ended December 31,
	2010			2011			2012			2010			2011			2012
	(in thousands)
Reconciliation of Adjusted EBITDA to net income (loss):
Net income (loss)	$	(11,612	)	$	(3,825	)	$	16,795		$	(4,119	)	$	3,140		$	481
Depreciation, depletion and amortization expense		2,568			4,022			6,377			3,079			2,858			2,742
Income tax expense (benefit)		36			101			81			(1,051	)		—			—
Interest expense, net		980			1,835			10,619			3,892			1,536			813
Changes in fair value of derivative instruments		—			—			—			(281	)		(243	)		—
Litigation settlement expense(1)		—			—			—			—			—			750
Gain on extinguishment of trade payable(2)		—			—			—			—			(1,212	)		—
Gain from debt restructuring(3)		—			—			—			—			(472	)		—
Other expense (income)		—			42			(112	)		(49	)		(99	)		(33	)
Provision for bad debts(4)		702			—			57			330			—			—
Impairment of land(5)		—			762			—			—			—			—
Equipment relocation costs(6)		—			572			—			—			—			—
(Gain) loss on disposal of equipment		—			364			(33	)		(180	)		(111	)		5

Adjusted EBITDA	$	(7,326	)	$	3,873		$	33,784		$	1,621		$	5,397		$	4,758

Reconciliation of Adjusted EBITDA to net cash provided by operating activities:
Net cash from (used for) operating activities	$	(1,298	)	$	2,482		$	2,201		$	3,145		$	(6,088	)	$	(1,065	)
Changes in operating assets and liabilities		(5,816	)		(1,210	)		22,580			(4,607	)		10,981			4,576
Litigation settlement expense(1)		—			—			—			—			—			750
Equipment relocation costs(6)		—			572			—			—			—			—
Income tax expense (benefit)		36			101			81			—			—			—
Interest expense, net		956			1,897			9,720			3,692			1,362			642
Interest converted to long-term debt(7)		(1,055	)		—			(743	)		(560	)		(759	)		—
Write-off of accounts receivable		—			(11	)		57			—			—			—
Write-down of inventory		(149	)		—			—			—			—
Other expense (income)		—			42			(112	)		(49	)		(99	)		(33	)
Provision for doubtful accounts		—			—			—			—			—			(112	)

Adjusted EBITDA	$	(7,326	)	$	3,873		$	33,784		$	1,621		$	5,397		$	4,758

(1): Reflects AEC's settlement of litigation that alleged environmental damage to property located contiguous to its bulk fuel terminal facility. The settlement agreement extinguished all liabilities, if any, and included mutual releases between the parties.
(2): Reflects AEC's settlement of a dispute with a supplier for less than the amount that had been reserved, which resulted in a gain in the amount of $1.2 million in 2011.
(3): Reflects gain at AEC of $0.5 million in 2011 resulting from the restructuring of its debt obligations.
(4): Reflects (a) a write-off at SSS in 2010 of a deposit to a supplier in the amount of $0.7 million and (b) a write-off of uncollectible accounts receivable at AEC in 2010 of $0.3 million.
(5): Reflects an impairment charge in 2011 at SSS in the amount of $0.8 million against the carrying value of a non-business generating asset originally acquired as part of the SSS acquisition in 2008 that was sold in 2012.
(6): Reflects the incurrence of costs in the amount of $0.6 million at SSS associated with relocating certain pieces of equipment from its Kosse, Texas facility to its New Auburn, Wisconsin facility in 2011.
(7): Reflects a portion of interest owed by SSS and AEC in 2010, 2011 and 2012 that was added to the outstanding principal amount.

	Pro Forma Predecessor SSS and AEC Combined									Historical Direct Fuels									Pro Forma Emerge Energy Services

	Year Ended December 31,									Year Ended December 31,									Year Ended December 31,
	2010			2011			2012			2010			2011			2012			2012
	(in thousands)
Reconciliation of Adjusted EBITDA to net income (loss):
Net income (loss)	$	(15,731	)	$	(685	)	$	17,276		$	10,844		$	15,454		$	11,553		$	27,130
Discontinued operations		—			—			—			(11,410	)		(1,499	)		—			—
Depreciation, depletion and amortization expense(1)		5,647			6,880			9,119			964			959			1,032			11,850
Income tax expense (benefit)		(1,015	)		101			81			30			220			82			163
Interest expense, net		4,872			3,371			11,432			3,166			1,365			1,165			12,597
Changes in fair value of derivative instruments		(281	)		(243	)		—			(97	)		80			(46	)		(46	)
Litigation expense settlement(2)		—			—			750			—			—			—			750
Gain on extinguishment of trade payable(3)		—			(1,212	)		—			1,779			—			—			—
Gain (loss) from debt restructuring(4)		—			(472	)					—			583			—			—
Other (income) expense		(49	)		(57	)		(145	)		—			—			—			(145	)
Provision for bad debts(5)		1,032			—			57			—			—			—			57
Impairment of land(6)		—			762			—			—			—			—			—
Equipment relocation costs(7)		—			572			—			—			—			—			—
(Gain) loss on disposal of equipment		(180	)		253			(28	)		—			—			—			(28	)

Adjusted EBITDA	$	(5,705	)	$	9,270		$	38,542		$	5,276		$	17,162		$	13,786		$	52,328

Reconciliation of Adjusted EBITDA to net cash provided by operating activities:
Net cash from (used in) operating activities	$	1,847		$	(3,606	)	$	1,136		$	(1,464	)	$	19,200		$	11,183		$	12,319
Earnings from Discontinued Operations(8)		—			—			—			(2,964	)		(1,398	)		—			—
Changes in operating assets and liabilities		(10,423	)		9,771			27,156			5,608			(1,902	)		1,741			28,897
Litigation expense settlement(2)		—			—			750			—			—			—			750
Equipment relocation costs(7)		—			572			—			—			—			—			—
Income tax expense (benefit)		36			101			81			30			220			82			163
Interest expense, net		4,648			3,259			10,362			2,452			1,072			810			11,172
Interest converted to long-term debt(9)		(1,615	)		(759	)		(743	)		—			—			—			(743	)
Write-off of accounts receivable		—			(11	)		57			—			—			—			57
Write-down of inventory		(149	)		—			—			—			—			—			—
Other expense (income)		(49	)		(57	)		(145	)		—			—			—			(145	)
Provision for doubtful accounts		—			—			(112	)		(30	)		(30	)		(30	)		(142	)
Realized loss on derivative financial instruments(10)		—			—			—			1,238			—			—			—
Costs associated with the sale of property, plant and equipment		—			—			—			406			—			—			—

Adjusted EBITDA	$	(5,705	)	$	9,270		$	38,542		$	5,276		$	17,162		$	13,786		$	52,328

We define operating working capital as the amount by which the sum of accounts receivable, inventory, prepaid expenses and other current assets exceeds the sum of accounts payable, accrued expenses and income taxes payable. Our definition of operating working capital differs from "working capital," as defined by GAAP, primarily because it excludes balance sheet items that are related to the capital structure of the business such as the current portion of long-term debt as well as the current portion of the capitalized lease liabilities. These items are influenced to a large extent by long-term capital structuring decisions, whereas the items included in our definition of operating working capital tend to fluctuate on a monthly basis based upon decisions made by management and the operation of the business. As a result, management uses operating working capital when measuring the effectiveness with which these key balance sheet items are being managed on a real-time basis.

The following tables present a reconciliation of operating working capital to net current assets, the most directly comparable GAAP measure, for the ends of each of the periods indicated:

	Pro Forma Predecessor SSS and AEC Historical Combined									Historical Direct Fuels									Pro Forma Emerge Energy Services

	As of December 31,									As of December 31,									As of December 31,
	2010			2011			2012			2010			2011			2012			2012
	(unaudited)									(unaudited)									(unaudited)
	(in thousands)
Total current assets	$	22,969		$	36,348		$	55,275		$	24,768		$	23,377		$	25,316		$	80,591
less: Total current liabilities		42,207			31,924			50,533			8,150			12,469			29,564			79,747

Net current assets (liabilities)		(19,238	)		4,424			4,742			16,618			10,908			(4,248	)		844
less: cash and cash equivalents		(5,264	)		(6,521	)		(1,465	)		(992	)		(4,229	)		(2,544	)		(4,009	)
less: lease receivable		—			—			(1,579	)		—			—			—			(1,579	)
less: assets held for sale		—			(1,338	)		—			(6,876	)		—			—			—
plus: deferred revenue		—			—			801			—			—			—			801
plus: current portion of long-term debt		7,158			677			9,322			1,700			1,838			17,067			26,039
plus: current portion of capital lease liability		120			1,990			1,548			—			—			—			1,548
plus: current portion of advances from customers		—			7,968			4,043			—			—			—			4,043
plus: current portion of seller notes and subordinated debt		13,052			—			—			—			—			—			—

Operating working capital	$	(4,172	)	$	7,200		$	17,412		$	10,450		$	8,517		$	10,275		$	27,687

MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

This Management's Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the "Selected Historical and Pro Forma Financial and Operating Data" beginning on page 78 and the accompanying financial statements and related notes included elsewhere in this prospectus. Unless otherwise indicated, all references to financial or operating data on a pro forma basis gives effect to the transactions described under "Summary—Partnership Structure and Offering-Related Transactions" on page 14 and in the unaudited pro forma combined financial statements included elsewhere in this prospectus. The following discussion contains forward-looking statements that are based on beliefs of our management, as well as assumptions made by, and information currently available to, our management. Actual results may differ materially from those discussed in or implied by forward-looking statements as a result of various factors, including those discussed below and elsewhere in this prospectus, particularly in the sections entitled "Risk Factors" beginning on page 29 and "Forward Looking Statements" on page 233.

We conduct our Sand operations through our subsidiary Superior Silica Sands LLC, or SSS, and our Fuel Processing and Distribution operations through our subsidiaries Insight Equity Acquisition Partners, LP, or Direct Fuels, and Allied Energy Company, LLC, or AEC. Following completion of this offering, our results of operations will be reported according to the segments we describe in this prospectus.

Our Sand segment currently consists of advanced facilities in New Auburn, Wisconsin, Barron County, Wisconsin and Kosse, Texas that are optimized to exploit the reserve profile in place at each location and produce high-quality frac sand. Frac sand is a critical component sold to and used by oilfield service companies to stimulate and maintain the flow of hydrocarbons in oil and natural gas wells that utilize hydraulic fracturing techniques. Our Wisconsin sand reserves provide us access to a wide range of high-quality sand that meets or exceeds all API specifications and includes coarse sands such as 16/30, 20/40 and 30/50 mesh sands, which have become the preferred sand for oil and liquids-rich gas drilling applications due to their coarseness, conductivity, high crush strength and comparative cost advantages over resin-coated sand or ceramic alternatives. Through our Wisconsin sand facilities and their interconnectivity to rail and other logistics infrastructure, we believe we are one of only a select group of sand producers capable of efficiently delivering the most highly sought after types of frac sands to all major unconventional resource basins currently producing in the United States and Canada. Our locations in Wisconsin also provide 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. We also mine frac sand at our facility in Kosse, Texas that is processed into a high-quality, 100 mesh frac sand, generally used in dry gas drilling applications. As a result of the quality and diversity of our sand reserves, we have the operational flexibility to alter a portion of our produced sand mix to meet customer needs across different price environments.

Our Fuel Processing and Distribution 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 transmix, which is a blend of different refined petroleum products that have become co-mingled in the pipeline transportation process, and process it into refined products such as conventional gasoline and low sulfur diesel. While a meaningful portion of our transmix business is conducted on a spot basis, we currently purchase approximately 63% of our supply of transmix pursuant to exclusive contracts having a volume-weighted average remaining duration of 17 months as of December 31, 2012. We design our contract structure to capture a stable margin, as the price differential between the indices at which we purchase transmix and wholesale supply and the sales price of the corresponding refined products tends to be stable. In addition to processing transmix and selling refined products, we provide a suite of complementary fuel products and services, including third-party terminaling services, the selling of wholesale petroleum products, certain reclamation services (which consist primarily of tank cleaning services) and blending of renewable fuels.

For the year ended December 31, 2012 we generated unaudited pro forma Adjusted EBITDA and pro forma net income of approximately $52.3 million and $27.1 million, respectively, of which approximately $33.8 million of pro forma Adjusted EBITDA was attributable to our Sand segment and approximately $18.5 million of pro forma Adjusted EBITDA was attributable to our Fuel Processing and Distribution segment. We expect that as we continue to grow our business, our Sand segment will contribute a significant majority of our cash available for distribution in the future. For the definition of Adjusted EBITDA and reconciliations to its most directly comparable financial measures calculated and presented in accordance with GAAP, please read "Selected Historical and Pro Forma Financial and Operating Data—Non-GAAP Financial Measures" beginning on page 83, and for a discussion of how we use Adjusted EBITDA to evaluate our operating performance, please read "—How We Evaluate Our Operations" beginning on page 92.

We derive our sales by mining, processing and distributing frac sand that our customers purchase in connection with the application of hydraulic fracturing techniques to oil and natural gas wells. As the majority of our sales volume is contracted for delivery at the mining facility such that customers bear shipping expenses, our sales are primarily a function of the price per ton realized at the point of sale and the volumes sold. Sand sold from our New Auburn facility is largely picked up by our customers at that facility. In connection with the commencement of operations at the Barron facility, we are now increasingly managing the logistics of shipping frac sand directly from that facility to the major oil producing basins. This provides our customers, for a fee, with readily available frac sand that can be picked up by truck from a site close to the well head. Our transportation revenues fluctuate based on a number of factors, including the volume of product we transport, service agreements with our customers, the mode of transportation utilized, the distance between our plants and customers, and the mode of transloading and storage utilized at the destination.

We sell our products primarily under long-term take-or-pay or fixed-volume supply agreements with customers in the oil and gas proppants market. Our contracts with our two largest customers, Schlumberger and Baker Hughes, are take-or-pay supply agreements that are designed to enhance the stability of our cash flows and mitigate our direct exposure to commodity price fluctuations. In the event that Schlumberger fails to purchase the minimum annual volume set forth in its agreement with us, it will be obligated to pay us an amount designed to compensate us, in part, for our lost margins on the unpurchased minimum volumes for that year. If the agreement is terminated during a contract year, the amount due to us will be calculated based on the number of months in that year in which the agreement was in effect. In the event that Baker Hughes fails to purchase the minimum annual volume set forth in its long-term supply agreement with us, it will be obligated to pay us an amount designed to compensate us, in part, for our lost margins on the unpurchased minimum volumes for that year.

We anticipate extending the term of the Baker Hughes agreement which expires in 2014 or, alternatively, replacing those sales volumes by entering into agreements with new customers. However, we may not be able to enter into new long-term contracts that contain take-or-pay provisions or on terms that are as favorable to us as our current take-or-pay contracts. Our current take-or-pay agreements define, among other commitments, the volume of product that our customers must purchase, the volume of product that we must provide, and the price that we will charge and that our customers will pay for each product. 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 prices. As a result, our realized prices may not grow or decline at rates consistent with broader industry pricing. For example, during periods of rapid price growth, our realized prices may grow more slowly than those of competitors, and during periods of price decline, our realized prices may decline from their current level but could outperform industry averages.

At the time our two primary customers entered into take-or-pay supply agreements with us, these customers provided advance payments for future shipments aggregating $13.0 million ($4.0 million of these payments was recorded on the balance sheet as customer advances as of December 31, 2012) in exchange for cash discounts on the price charged per ton of sand. As a result, the cash we receive from these customers is less than the revenue we record for such sales. We anticipate the advances will be fully retired in the last half of 2013, thus eliminating the cash discount on purchased sand.

We also sell our products through long-term fixed-volume supply agreements, which are contractual relationships that commit customers to take a fixed volume of sand with prices determined based on a specific pricing formula. Unlike take-or-pay contracts, fixed-volume contracts do not include pre-determined liquidated damage penalties in the event the customer fails to purchase the minimum contracted volume commitment.

Collectively, sales to customers with long-term take-or-pay sales agreements in 2012 accounted for approximately 89% of our total Sand segment sales volumes. Sales to fixed-volume customers comprised another 5% of our total Sand segment sales volumes, with sales to efforts-based and spot market customers constitutes the remaining 6%. As of December 31, 2012, our long-term take-or-pay agreements tied to New Auburn plant customers covered approximately 58% of our 1.3 million tons of the plant's annual production capacity, while 210,000 tons of the Barron dry plant's 2.4 million tons of capacity is committed to other contract customers under a combination of take-or-pay, long-term and fixed-volume contracts. Additionally, we believe that a combination of high quality sand reserves, a highly customizable production mix, efficient production operations and our broad portfolio of flexible supply chain solutions, including unit train delivery, provide us a competitive advantage when competing for sales volume in the spot market.

We invoice the majority of our clients on a per shipment basis, although for some larger customers, we consolidate invoices weekly or monthly. Standard terms are net 30 days and our customers typically remit payment to us within 30 to 35 days of receiving an invoice. The amounts invoiced include the amount charged for the product, transportation costs (if paid by us) and, as applicable, costs for additional services, such as costs related to product transloading, storage and rail car maintenance, cleaning or storage.

Due to sustained freezing temperatures in Wisconsin during winter months, it is common industry practice to halt excavation and wet plant operations during those months. As a result, our Wisconsin operations excavate and wash sand in excess of current delivery requirements during the months when our excavation and wet plant operations are ongoing. This excess sand is placed in stockpiles that feed our dry plant operations and fill customer orders throughout the year.

We derive substantially all of our Fuel Processing and Distribution revenues by selling petroleum products to local retailers, jobbers and end users in the Dallas-Fort Worth and Birmingham markets. In

addition, we provide terminal throughput, reclamation, and certain freight services to our customers, which collectively constituted approximately 1% of our Fuel Processing and Distribution sales in 2012.

We sell our fuel to a broad customer base using a mix of contract and spot sales. Our sales contracts define the price formula at which we sell to contract customers. While pricing for contract customers tends to be slightly below pricing for spot customers, our contract customers provide a consistent and reliable base of revenue. Pricing for contract customers is tied directly to daily fuel price indices and for other customers is based on market rates that approximate what other sellers of unbranded fuel are charging in the Dallas-Fort Worth and Birmingham markets on any given day. We design our contract structure to capture a stable margin, as the price differential between the indices at which we purchase transmix and wholesale supply and the sales price of the corresponding refined products tends to be stable. Approximately 62% of our fuel and wholesale fuel sold during the year ended December 31, 2012 was sold under contracts with a volume-weighted average remaining term of four months as of December 31, 2012. These contracts range in duration from month-to-month contracts to a contract with an 12-month remaining duration. Our customers do not typically distinguish whether the source of the product was from our transmix processing operations or from our purchases of wholesale fuel.

Our terminal throughput customers pay us a fixed fee for every gallon of fuel that they sell across our truck rack. In addition, other fees may be charged for certain additives and injection services. We provide terminal services based on contracts that range in duration from month-to-month (approximately 70% of our customers as of December 31, 2012) to up to 30 months (30% of our customers as of December 31, 2012). We also provide reclamation services, primarily tank cleaning, on a fixed fee basis to our customers. We have a fleet of 15 tractors and 25 trailers that we use for hauling petroleum products and to support our reclamation business. These vehicles are used primarily for in-house activity but we also provide transportation services for outside customers.

Invoices for fuel products are sent to our customers daily and our customers typically remit payment to us through our draw on their bank accounts 10 days after the invoice date.

The principal expenses involved in conducting our business are labor costs, electricity and drying fuel costs, fees paid to our contract mine operator, transportation costs and maintenance and repair costs for our mining and processing equipment and facilities. Our fixed costs are relatively low and after we have satisfied our minimum purchase obligations, a large portion of the costs we incur in our Sand segment are only incurred when we produce saleable frac sand. Consequently, our margins are generally insulated from increases or decreases in our sales volumes, as our costs of production as a percentage of revenues are relatively constant. We believe the majority of our operating costs have relatively stable prices associated with them, as we have either contractually fixed the unit cost of most critical cost components, such as the costs associated with extracting our minerals, trucking wet sand to our dry plants and the royalty payments relating to our sand reserves, or obtained the ability to pass on such costs to customers, subject to certain limitations. As our production levels increase, we do recognize some cost benefits associated with economies of scale.

We have engaged Fred Weber, a specialized third party provider, to perform the mining operations at our New Auburn location and to satisfy a portion of our wet processing needs at that facility. Under our agreement with Fred Weber, we have agreed to purchase a minimum number of tons of washed sand from Fred Weber under take-or-pay conditions each year until the contract expires in September 2016. A portion of the cash payment we make to Fred Weber under the agreement is treated as a capital lease payment, given that we will own the plant at the end of the capital lease period. The cost of goods sold reflected in our financial statements includes only the portion of the payment to Fred Weber that is not attributable to the capital lease payment. Recognized contract mining and wet

processing fees due to Fred Weber were our largest operating expenditure in 2012, accounting for approximately 17% of our revenues in that year. We anticipate Fred Weber will continue to represent a material portion of our cost structure for the next several years and have negotiated fixed rates, which adjust based on actual volume purchased, for the services we anticipate Fred Weber will provide during that time.

Additionally, we incur expenses related to our corporate operations, including costs for selling and marketing; research and development; finance; legal; and environmental, health and safety functions of our Sand operations. These costs are principally driven by personnel expenses. In total, our selling, general and administrative costs represented approximately 9% of our Sand revenues in 2012.

Direct plant labor costs represented approximately 3% of our Sand revenues in 2012. We do not employ any union labor.

We capitalize the costs of our mining equipment and generally depreciate it over its expected useful life. Depreciation, depletion and amortization expenses represented approximately 10% of our Sand revenues for 2012. Preventive and remedial repair and maintenance costs that do not involve the replacement of major components of our equipment and facilities are expensed as incurred. These repair and maintenance costs can be significant due to the abrasive nature of our products and represented approximately 2% of our Sand revenues in 2012.

We incur significant costs for electricity and drying fuel (principally natural gas) in connection with the operation of our processing facilities. Electricity and dryer fuel costs represented 1% and 2% of our Sand revenues in 2012, respectively, and all our plants are serviced by three-phase power and natural gas lines.

We own or have long-term mineral rights leases for the frac sand that we mine and process. The mineral rights leases relating to our mineral reserves require us to pay a per ton royalty payment to the land owners and other third parties. Including the production facility in Barron County, Wisconsin, those payments range from $1.00 to $1.38 per ton of product shipped from the wet plant site to the dry plant location. Additionally, in order to secure access to an additional supply of coarse sand for the start-up of our Barron facility, we recently entered into a ten-year supply agreement with Midwest Frac under which we will be obligated to purchase at least 200,000 tons of wet sand per year from Midwest Frac's mine under take-or-pay conditions.

The cost of goods, which includes cost of fuel and labor, is the most significant expense that we incur (approximately 97% of operating costs in 2012). We purchase our transmix, wholesale fuel and other feedstocks based on several different regional price indices, the most important of which are Platts Gulf Coast gasoline and diesel price postings. The price of our purchases is set on the day that we purchase the product. We typically sell our fuel within 7 to 10 days of our purchase. When there are large surges in our supply of transmix, our holding period for inventory can increase but it tends to normalize within a short period. We use hedging products for our Fuel Processing and Distribution operations in order to stabilize our margins with respect to diesel and gasoline.

Sale of products produced from our transmix operations represented approximately 41% of our fuel revenues in 2012. The majority of our transmix (63%) is purchased under exclusive supply contracts with a volume-weighted average remaining duration of approximately 17 months as of December 31, 2012. Wholesale fuel represents the remainder of our fuel purchases. This fuel is purchased under market based supply contracts ranging from 3 to 12 months in duration.

Our reported fuel revenues and cost of fuel both include state and federal excise taxes that we collect on behalf of governmental bodies and then remit to them on a periodic basis. These taxes have no impact on our profitability. In 2012, we collected and remitted approximately $43.8 million of excise taxes.

Other costs relating to selling, administrative, depreciation and amortization expenses collectively represented only 1% of operating costs in 2012.

Our management uses a variety of financial and operational metrics to analyze our performance. Our business is organized into our Sand segment and our Fuel Processing and Distribution segment. We evaluate the performance of these segments based on their volumes sold, gross profit per unit, segment gross profit, selling, general and administrative expenses and segment 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 refined products and frac sand 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. For our Sand segment, the ratio of sand sold that is tailored to dry gas applications versus oil and liquids-rich gas applications is important because changing commodity prices can influence spot market margins for each product set. Although winter weather impacts the months during which we can wash frac sand in Wisconsin, seasonality is not a significant factor in determining our ability to supply sand to our customers because we are able to sell frac sand year-round by accumulating a stockpile of wet sand during non-winter months and then dry-process and sell that sand during winter months. However, 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 those areas may be adversely affected. For example, we could experience a decline in volumes sold and segment EBITDA 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. There are no significant seasonal factors that increase or decrease the sales of transmix in any given quarter. For a discussion of the impact of weather on our Sand operations, please read "Risk Factors—Our cash flows fluctuate on a seasonal basis and severe weather conditions could have a material adverse effect on our business" beginning on page 36.

Gross profit per unit. The product margin per gallon that we realize for selling gasoline or diesel is the difference between the price that we pay to buy the product, including the cost of inbound transportation, the cost of any additives that may be blended with the product, certain direct operating and maintenance expenses, and the price at which we sell that product to our customers. We believe this is the best measure of the profitability of each gallon of our refined product. The product margin for frac sand is the difference between the cost to mine each ton of sand considering both the wet and dry operations and the price at which we sell each ton as determined by our sales contracts or by the then prevailing market price if it is a spot sale. When we sell product to the customer at a location near the drill site, our margin is incrementally impacted by the price we receive for the supply chain services rendered, net of our transportation, transload, and storage costs.

Segment gross profit. Segment gross profit is a key metric that management uses to evaluate our operating performance. This measure is a good estimate of our variable product contribution.

Selling, general and administrative expenses. In addition to the foregoing measures, we also monitor our selling, general and administrative expenses. These costs represent a small portion of our total costs (2% of total 2012 operating expenses); however, it is still very important to us that we control them. Our selling, general and administrative expenses include costs necessary to provide administrative support necessary to run our business. In the future, we estimate that we will incur incremental general and administrative expenses of approximately $3.5 million per year as a result of being a publicly traded limited partnership. These costs include those associated with annual and quarterly SEC reporting; tax return and Schedule K-1 preparation and distribution expenses; Sarbanes-Oxley compliance expenses; expenses associated with listing on the NYSE; independent auditor fees; legal

fees; investor relations expenses; registrar and transfer agent fees; director and officer liability insurance costs; and outside director compensation.

We include in this prospectus the non-GAAP financial measure Adjusted EBITDA, and provide reconciliations of Adjusted EBITDA to net income (loss) and cash flow from operating activities, our most directly comparable financial performance and liquidity measures calculated and presented in accordance with GAAP. Although we have not quantified distributable cash flow on a historical basis, after the closing of this offering we intend to use distributable cash flow, which we define as Adjusted EBITDA plus borrowings to fund growth capital expenditures, less cash paid for incremental annual general and administrative expenses of being a publicly traded partnership, cash paid for interest expense, and maintenance capital expenditures, to analyze our performance. Distributable cash flow will not reflect changes in working capital balances. Adjusted EBITDA and distributable cash flow are 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:

We define Adjusted EBITDA 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. We expect to be required to report Adjusted EBITDA (which as defined includes certain other adjustments, none of which impacted the calculation of Adjusted EBITDA in the periods reflected in this prospectus) to our lenders under our anticipated new revolving credit facility and to use it in determining our compliance with the interest coverage ratio test and certain senior consolidated indebtedness to Adjusted EBITDA tests thereunder.

Adjusted EBITDA should not be considered as an alternative to net income, operating income, cash flow from operating activities or any other measure of financial performance presented in accordance with GAAP. Our Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA in the same manner. For a reconciliation of Adjusted EBITDA to its most directly comparable financial measures, calculated and presented in accordance with GAAP, please read "Selected Historical and Pro Forma Financial and Operating Data—Non-GAAP Financial Measures—Adjusted EBITDA" beginning on page 83.

We also include in this prospectus the non-GAAP financial measure operating working capital, and provide a reconciliation of operating working capital to net current assets, our most directly comparable financial performance measure calculated and presented in accordance with GAAP.

capital structuring decisions whereas the items included in our definition of operating working capital tend to fluctuate on a monthly basis based upon decisions made by management and the operation of the business. As a result, management uses operating working capital when measuring the effectiveness with which these key balance sheet items are being managed on a real-time basis. For a reconciliation of operating working capital to net current assets, our most directly comparable financial performance measure calculated and presented in accordance with GAAP, please read "Selected Historical and Pro Forma Financial and Operating Data—Non-GAAP Financial Measures—Operating Working Capital" beginning on page 86.

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. According to the PropTester® Report, the volume of global demand for frac sand increased at a compound annual growth rate of approximately 28.5% from 2008 to 2012. The PropTester® Report estimates the 2012 global frac sand market consumption (and sand substrate used for resin coating) at approximately 31.8 million tons, an increase of approximately 3.2 million tons (or 11.2%) compared to approximately 28.6 million tons in 2011. According to the Freedonia Report, North American proppant demand by weight is projected to continue growing by 7.2% per year through 2016.

In addition to the overall increase in the number of horizontal drilling rigs, over the last four 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. For example, according to the North American rig count data published by Baker Hughes Inc., at January 4, 2008, there were approximately 300 rigs drilling for oil and 1,450 rigs drilling for natural gas in the United States. At December 31, 2012, there were over 1,300 drilling rigs operating in oil- and liquids-rich natural gas areas of the United States, while the dry natural gas rig count had declined to approximately 430. We anticipate that the increased growth in demand for frac sand in 2011 and 2012 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 Ottawa white frac sand.

The increased demand for frac sand from customers in the oil and gas proppants market has resulted in favorable pricing trends over the past few years for frac sand producers. According to the Freedonia Report, frac sand prices increased at an average annual rate of 4.7% from 2001 to 2011. In addition, the shift of drilling activity in the United States 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 risen more than the prices for finer frac sand since 2008. The U.S. Bureau of Labor Statistics Producer Price Index for Industrial Sand Mining—Secondary Products, which includes frac sand, suggests that prices rose 2.4% during the twelve month period ended December 31, 2012. Certain data points indicate that spot prices for frac sand have declined in recent months, but we currently believe that we retain the ability to enter into contracts for frac sand sales at prices at least as favorable to us as our current take-or-pay contracts.

Total consumption of liquid fuels in the United States, including both fossil fuels and biofuels, is expected to remain relatively stable from 2010 (19.2 million barrels per day) to 2035 (to 21.9 million barrels per day), according to the Annual Energy Outlook 2012 published by the Energy Information Administration, or EIA, in June 2012. The transportation sector is expected to continue to account for

the largest percentage of demand for liquid fuels (as measured by energy content), accounting for approximately 72% of total liquids consumption in 2010 and in 2035.

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. According to the EIA, consumption of liquid fuels is forecasted to grow by approximately 0.5% per year between 2010 and 2035. 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 communication with the EPA indicates that the agency will likely 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. The settlement communication will allow the sale of 500 ppm diesel produced by transmix processors to certain marine markets with no phase-out date.

The following table sets forth selected unaudited pro forma financial and operating data for us for the periods presented. Our selected pro forma financial and operating data as of December 31, 2012 and the year ended December 31, 2012 are derived from our pro forma unaudited condensed combined financial statements included elsewhere in this prospectus. Our pro forma unaudited financial statements consist of the pro forma combined results of SSS and AEC as if such combination occurred on January 1, 2010 and give effect to the acquisition of Direct Fuels as if such acquisition occurred on January 1, 2012 for statement of operations purposes and December 31, 2012 for balance sheet purposes. We have not given pro forma effect to incremental selling, general and administrative expenses of approximately $3.5 million that we expect to incur annually as the result of being a publicly traded partnership.

The following table should be read in conjunction with "Selected Historical and Pro Forma Financial and Operating Data" beginning on page 78. See "—Historical Financial and Operating Data" beginning on page 103 for a table setting forth the selected historical combined financial and operating data of our predecessor.

	Pro Forma Predecessor SSS and AEC Historical Combined									Historical Direct Fuels									Pro Forma Emerge Energy Services

	Year Ended December 31,									Year Ended December 31,									Year Ended December 31,
	2010			2011			2012			2010			2011			2012			2012
	(unaudited)																		(unaudited)
	(in thousands)
Statements of Operations Data:
Revenues	$	261,607		$	377,488		$	624,096		$	225,249		$	261,557		$	332,767		$	956,863
Operating expenses:
Cost of goods sold(1)		257,283			359,250			575,404			215,907			239,886			315,169			890,573
Selling, general and administrative		10,029			8,968			10,150			4,066			4,509			3,812			13,962
Depreciation, depletion and amortization(2)		5,647			6,880			9,119			964			959			1,032			11,850
Provision for bad debts		1,032			—			57			—			—			—			57
Impairment of land		—			762			—			—			—			—			—
Equipment relocation costs		—			572			—			—			—			—			—
(Gain) loss on disposal of equipment		(180	)		253			(28	)		—			—			—			(28	)

Total operating expenses		273,811			376,685			594,702			220,937			245,354			320,013			916,414

Operating income (loss)		(12,204	)		803			29,394			4,312			16,203			12,754			40,449

Other expense (income):
Interest expense		4,872			3,371			11,432			3,166			1,365			1,165			12,597
Litigation settlement		—			—			750			—			—			—			750
Gain on extinguishment of trade payable		—			(1,212	)		—			1,779			—			—			—
Loss (gain) from debt restructuring		—			(472	)		—			—			583			—			—
Changes in fair market value of interest rate swap		(281	)		(243	)		—			(97	)		80			(46	)		(46	)
Other expense (income)		(49	)		(57	)		(145	)		—			—			—			(145	)

Total other expense, net		4,542			1,387			12,037			4,848			2,028			1,119			13,156

Income (loss) before tax expense		(16,746	)		(584	)		17,357			(536	)		14,175			11,635			27,293
Provision for state franchise and margin taxes		(1,015	)		101			81			30			220			82			163

Income (loss) from continuing operations		(15,731	)		(685	)		17,276			(566	)		13,955			11,553			27,130

Income from discontinued operations		—			—			—			1,814			1,569			—			—
Gain (loss) on sale of discontinued operations		—			—			—			9,596			(70	)		—			—

Net income (loss)	$	(15,731	)	$	(685	)	$	17,276		$	10,844		$	15,454		$	11,553		$	27,130

Balance Sheet Data (at period end):
Property, plant and equipment, less accumulated depreciation	$	62,966		$	77,446		$	120,851		$	8,837		$	8,423		$	8,743
Total assets		100,314			127,580			195,787			34,286			32,484			35,426
Total liabilities		126,827			135,360			186,291			31,513			20,507			29,564
Total partners'/ members' equity		(26,513	)		(7,780	)		9,496			2,773			11,977			5,862
Cash Flow Data:
Net cash provided by (used in)
Operating activities		1,847			(3,606	)		1,136			(1,464	)		19,200			11,183
Investing activities		(1,536	)		(14,754	)		(39,074	)		15,748			6,433			(1,353	)
Financing activities		3,462			19,617			32,883			(14,496	)		(22,396	)		(11,516	)
Other Financial Data:
Adjusted EBITDA		(5,705	)		9,270			38,542			5,276			17,162			13,786			52,328
Capital Expenditures:
Maintenance(3)		(681	)		(974	)		(2,520	)		(184	)		(336	)		(458	)
Growth(4)		(1,056	)		(14,205	)		(37,945	)		(68	)		(231	)		(895	)

Total	$	(7,442	)	$	(5,909	)	$	(1,923	)	$	5,024		$	16,595		$	12,433

In this section, we discuss our pro forma results of operations, liquidity and capital resources and provide quantitative and qualitative disclosures about market risk on a pro forma combined basis for Emerge Energy Services LP, giving effect to the pro forma adjustments set forth in this prospectus under "Selected Historical and Pro Forma Financial and Operating Data" beginning on page 78.

We believe that the pro forma discussion set forth below will provide useful information to investors because it depicts our business as it will exist following completion of this offering and provides further details regarding our unaudited pro forma condensed combined financial statements included elsewhere in this prospectus and allows us to further discuss the changes that occurred in our business during the periods indicated. While management believes that that the pro forma discussion set forth below accurately depicts our business, our actual results may differ materially from those discussed below or implied by forward-looking statements as a result of various factors, including those discussed elsewhere in this prospectus, particularly in the sections entitled "Risk Factors" beginning on page 29 and "Forward Looking Statements" on page 233. Accordingly, our historical pro forma results of operation might not be indicative of future results.

Factors Affecting the Comparability of the Pro Forma Results of the Partnership to the Historical Financial Results of Our Predecessor

Our unaudited pro forma results of operations may not be comparable to the historical operations of SSS and AEC for the periods presented or to our future financial results, primarily for the reasons described below:

Please also read "—Historical and Financial Operations Data—Factors Affecting the Comparability of the Historical Financial Results" beginning on page 105.

Following the closing of this offering we expect our sources of liquidity to include:

We anticipate that we will continue to make significant growth capital expenditures in the future, including acquiring new facilities or expanding our existing facilities as market demands dictate. Consequently, our ability to develop and maintain sources of funds to meet our capital requirements is critical to our ability to meet our growth objectives. We expect that our future growth capital expenditures will be funded by borrowings under our anticipated new revolving credit facility and the issuance of debt and equity securities. However, we cannot assure you that we will be able to raise additional funds on favorable terms.

In addition to distributions on our equity interests, our primary short-term liquidity needs will be to fund general working capital requirements, while our long-term liquidity needs will primarily relate to growth capital expenditures and acquisitions. We believe that cash from operations will be sufficient to meet our existing short-term liquidity needs for at least the next 12 months.

Our long-term liquidity needs will generally be funded from cash from operations, borrowings under our anticipated new revolving credit facility and other debt or equity financings. We cannot assure you that we will be able to raise additional funds on favorable terms. For more information, please read "—Capital Requirements" beginning on page 100.

In determining the amount of cash available for distribution, the board of directors of our general partner will determine the amount of cash reserves to set aside for our operations, including reserves for future working capital, maintenance capital expenditures, growth capital expenditures, acquisitions and other matters, which will impact the amount of cash we are able to distribute to our unitholders. However, we expect that we will rely primarily upon external financing sources, including borrowings under our anticipated new revolving credit facility and issuances of debt and equity securities, as well as cash reserves, to fund our growth capital expenditures including acquisitions. To the extent we are unable to finance growth externally and are unwilling to establish cash reserves to fund future expansions, our cash available for distribution will not significantly increase. 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 any growth capital expenditures including acquisitions, 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 or in the terms of our anticipated new revolving credit facility on our ability to issue additional units, including units ranking senior to the common units.

We define operating working capital as the amount by which the sum of accounts receivable, inventory, prepaid expenses and other current assets exceeds the sum of accounts payable, accrued expenses and income taxes payable. For a reconciliation of operating working capital to net current assets, our most directly comparable financial performance measure calculated and presented in accordance with GAAP, please read "Selected Historical and Pro Forma Financial and Operating Data—Non-GAAP Financial Measures—Operating Working Capital" beginning on page 86 and for a discussion of how we use operating working capital to evaluate certain non-capital structure balance sheet accounts on a real-time basis, please read "—How We Evaluate Our Operations" beginning on page 92.

Our pro forma operating working capital was $27.7 million as of December 31, 2012. From December 31, 2011 to December 31, 2012, AEC's operating working capital increased approximately $4.0 million, due to a $7.9 million increase in current assets, which primarily consisted of accounts receivable and inventory, offset by a $3.9 million increase in accounts payable and accrued expenses. The increase in current assets was consistent with the 60% increase in revenues that AEC achieved over the time period, and was offset by increases in accounts payable and accrued expenses resulting from a commensurate increase in cost of goods sold. Direct Fuels' operating working capital increased to $1.8 million over the period, which was primarily the result of a $5.1 million increase in accounts receivable and inventory balances at the end of the period, offset by a $1.8 million increase in accounts payable and accrued expenses. SSS experienced a $6.2 million increase in operating working capital during the period, primarily resulting from an increase in operating working capital to support commencement of operations at the Barron County facility in December 2012.

In conjunction with this offering, we expect to replace our existing credit facilities and enter into a new revolving credit facility that will include a $ million revolver. The revolver will mature in , and borrowings will bear interest at a variable rate per annum equal to the lesser of LIBOR or the Base Rate, as the case may be, plus the Applicable Margin (LIBOR, Base Rate and Applicable Margin each will be defined in the credit agreement that evidences our anticipated new revolving credit facility). We will use the proceeds from borrowings under our anticipated new revolving credit facility to (i) make a $ million, $ million and $ million distribution to SSH, AEC Holdings and DF Parent, respectively, and (ii) pay fees and expenses of approximately $ million relating to our anticipated new revolving credit facility. We also expect that we may use borrowings under our anticipated new revolving credit facility for (i) refinancing existing indebtedness, (ii) working capital and other general partnership purposes and (iii) capital expenditures.

Borrowings under our anticipated new revolving credit facility will be secured by a first-priority lien on and a security interest in substantially all of our assets. The credit agreement that evidences our anticipated new revolving credit facility will contain customary covenants, including restrictions on our ability to incur additional indebtedness, make certain investments, loans or advances, make distributions to our unitholders, make dispositions or enter into sales and leasebacks, or enter into a merger or sale of our property or assets, including the sale or transfer of interests in our subsidiaries. The events that constitute an Event of Default under our new revolving credit agreement are expected to be customary for loans of this size and type.

The net proceeds from this offering, together with approximately $ million in borrowings under our anticipated new revolving credit facility, will be used as set forth under "Use of Proceeds" beginning on page 65.

We expect to have approximately $ million available under our anticipated new revolving credit facility after the closing of this offering

Maintenance capital expenditures are capital expenditures required to maintain, over the long term, our asset base, operating income or operating capacity. Capital expenditures made solely for investment purposes will not be considered maintenance capital expenditures. The primary purpose of maintenance capital is to maintain production at a steady level over the long term to maintain our distributions per unit. For the year ended December 31, 2012, maintenance capital expenditures were $3.0 million.

Growth capital expenditures are capital expenditures that we expect to increase, over the long term, our asset base, operating income or operating capacity. Growth capital expenditures will also include interest (and related fees) on debt incurred to finance all or any portion of the construction of such capital improvement in respect of the period that commences when we enter into a binding obligation to commence construction of a capital improvement and ending on the earlier to occur of the date any such capital improvement commences commercial service and the date that it is abandoned or disposed of. Capital expenditures made solely for investment purposes will not be considered growth capital expenditures. The primary purpose of growth capital expenditures is to build or acquire assets that will increase our distributions per unit in a manner that is expected to be accretive to our unitholders. Growth capital expenditures were $38.8 million for the year ended December 31, 2012, the primary driver of which was the construction of the Barron County facility.

We are exposed to market risk, including the effects of adverse changes in commodity prices and interest rates as described below. The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term "market risk" refers to the risk of loss arising from adverse changes in commodity prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.

Our major market risk exposure is in the pricing that we receive for our sand and transmix 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 may 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; this termination may not occur earlier than December 2014. Prices under all of our supply agreements are generally fixed and are subject to adjustment, with limitation, in response to certain cost increases or decreases. As a result, our realized prices for our 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 our sand production.

Our financial results from our Fuel Processing and Distribution 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 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. 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.

We utilize financial hedging arrangements 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 Processing and Distribution segment. Certain unusual events beyond our control may occur that result in an unexpected increase in our holding period, which would have a negative impact on our margins. For example, an economic slowdown similar to the global economic recession that began in the second half of 2008 or a significant increase in pipeline transit time could increase our commodity price exposure and have an adverse effect on our financial results.

The derivative commodity instruments that we utilize consist mainly of futures traded on the New York Mercantile Exchange. We do not designate these commodity instruments as cash flow hedges under Accounting Standards Codification (ASC) 815, Derivatives and Hedging. As a result, we record them at fair value on the consolidated balance sheet with resulting gains and losses reflected in cost of fuel as reported in the consolidated statement of operations. Our derivative commodity instruments serve the same risk management purpose whether designated as a cash flow hedge or not. We derive the fair values of our derivative commodity instruments principally from published market quotes. The precise level of our open position derivatives is dependent on inventory levels, expected inventory purchase patterns and market price trends.

We expect to adopt a derivative commodity instrument policy designed to reduce the impact to our cash flows from commodity price volatility. By removing a significant portion of price volatility associated with production, we believe we will mitigate, but not eliminate, the potential negative effects of reductions in commodity prices on our cash flow from operations for those periods. However, our activities may also reduce our ability to benefit from increases in commodity prices.

On a pro forma basis as of December 31, 2012, we had debt outstanding of $ million, with an assumed weighted average interest rate of LIBOR plus % and expenses on the unused borrowing base, or %. Assuming no change in the amount outstanding, the impact on interest expense of a 10% increase or decrease in the average interest rate would be approximately $ million. In the future, we anticipate entering into interest rate derivative contracts on a portion of our outstanding debt to mitigate the risk of fluctuations in LIBOR.

We are subject to risk of losses resulting from nonpayment or nonperformance by our counterparties to interest and commodity driven instruments. Should the creditworthiness of one or more of our counterparties decline, our ability to mitigate nonperformance risk is limited to a counterparty agreeing to either a voluntary termination and subsequent cash settlement or a novation of the derivative contract to a third party. In the event of a counterparty default, we may sustain a loss which could negatively impact cash receipts.

We are subject to risk of losses resulting from nonpayment or nonperformance by our customers. In our Sand segment, our top three customers accounted for 42%, 28% and 13% of our pro forma Sand revenues for the year ended December 31, 2012. In our Fuel Processing and Distribution segment, our top three customers accounted for 17%, 14%, and 10% of our pro forma Fuel Processing and Distribution revenue for the year ended December 31, 2012.

We do not plan to require our customers to post collateral, but we will examine the creditworthiness of our customers to whom credit is extended and to manage exposure to credit risk through credit analysis, credit approval, credit limits and monitoring procedures. This evaluation may include, in the case of customers with whom we have receivables, reviewing their historical payment record and undertaking the due diligence necessary to determine credit terms and credit limits.

The following table sets forth selected historical combined financial and operating data of SSS and AEC, which together constitute our predecessor for accounting purposes, for the periods presented. The following table should be read in conjunction with "Selected Historical and Pro Forma Financial and Operating Data" beginning on page 78.

	Predecessor Historical

	SSS									AEC
	Year Ended December 31,									Year Ended December 31,
	2010			2011			2012			2010			2011			2012
	(in thousands)
Statements of Operations Data:
Revenues	$	17,131		$	28,179		$	66,697		$	244,476		$	349,309		$	557,399
Operating expenses:
Cost of goods sold(1)		18,211			19,311			27,401			239,072			339,939			548,003
Selling, general and administrative		6,246			4,995			5,512			3,783			3,973			4,638
Depreciation, depletion and amortization		2,568			4,022			6,377			3,079			2,858			2,742
Provision for bad debts		702			—			57			330			—			—
Impairment of land		—			762			—			—			—			—
Equipment relocation costs		—			572			—			—			—			—
(Gain) loss on disposal of equipment		—			364			(33	)		(180	)		(111	)		5

Total operating expenses		27,727			30,026			39,314			246,084			346,659			555,388

Operating income (loss)		(10,596	)		(1,847	)		27,383			(1,608	)		2,650			2,011

Other expense (income):
Interest expense		980			1,835			10,619			3,892			1,536			813
Litigation settlement expense		—			—			—			—			—			750
Gain on extinguishment of trade payable		—			—			—			—			(1,212	)		—
Gain from debt restructuring, net		—			—			—			—			(472	)		—
Changes in fair market value of interest rate swap		—			—			—			(281	)		(243	)		—
Other expense (income)		—			42			(112	)		(49	)		(99	)		(33	)

Total other expense, net		980			1,877			10,507			3,562			(490	)		1,530

Income (loss) before tax expense		(11,576	)		(3,724	)		16,876			(5,170	)		3,140			481
Provision for state franchise and margin taxes		36			101			81			(1,051	)		—			—

Net income (loss)	$	(11,612	)	$	(3,825	)	$	16,795		$	(4,119	)	$	3,140		$	481

Balance Sheet Data (at period end):
Property, plant and equipment, less accumulated depreciation	$	19,853		$	36,310		$	80,749		$	43,113		$	41,136		$	40,102
Total assets		35,449			59,511			121,498			64,865			68,069			74,289
Total liabilities		65,223			92,877			138,069			61,604			42,483			48,222
Total Partners'/ members' equity		(29,774	)		(33,366	)		(16,571	)		3,261			25,586			26,067
Cash Flow Data:
Net cash provided by (used in):
Operating activities		(1,298	)		2,482			2,201			3,145			(6,088	)		(1,065	)
Investing activities		(1,384	)		(13,912	)		(37,690	)		(152	)		(842	)		(1,384	)
Financing activities		4,465			14,007			31,088			(1,003	)		5,610			1,795
Other Financial Data:
Adjusted EBITDA		(7,326	)		3,873			33,784			1,621			5,397			4,758
Capital Expenditures
Maintenance(2)		(328	)		(748	)		(1,248	)		(353	)		(226	)		(1,272	)
Growth(3)		(1,056	)		(13,495	)		(37,814	)		—			(710	)		(131	)

Total	$	(8,710	)	$	(10,370	)	$	(5,278	)	$	1,268		$	4,461		$	3,355

The historical results of operations for each of our predecessor among the periods may not be comparable, either to each other or to our future results of operations, for the reasons described below:

As a result of the factors listed above, historical results of operations and period-to-period comparisons of these results and certain financial data may not be comparable or indicative of future results.

SSS's revenues increased by $38.5 million, or 137%, to $66.7 million for the year ended December 31, 2012 compared to $18.2 million for the year ended December 31, 2011. Revenues for our Kosse 100 mesh product increased $1.5 million from period to period, driven by a 19% increase in volume, which accounted for $0.9 million of the increase, combined with a 23% increase in the average selling price, accounting for the remaining $0.7 million increase. Sales volumes for our northern Ottawa white frac sand sold from our Wisconsin facilities increased 633% from the 2011 period to the 2012 period, which resulted in a $51.8 million increase in SSS's revenues. Conversely, the decision to focus our efforts on sales from our Wisconsin plants (which produce higher marginal revenues) resulted in a $15.4 million decrease in sand revenues realized from our Kosse facility. The 220% total increase in 100 mesh and northern Ottawa white frac sand sales was primarily attributable to robust drilling activity combined with the enhanced sales volumes recognized from operating the New Auburn facility for a full year. The operations at SSS's New Auburn facility accounted for 87% of total frac sand sales volume during the year ended December 31, 2012 and accounted for approximately $60.2 million of SSS's revenues during this period. Other revenue increased $0.6 million, primarily as a result of higher transportation and non-frac sand sales revenue.

SSS's cost of goods sold, as a percent of revenue, decreased by 27.4%. On a dollar basis, SSS's cost of goods sold increased by $8.1 million, or 42%, to $27.4 million for the year ended December 31, 2012 compared to $19.3 million for the year ended December 31, 2011. Increased production of northern Ottawa white sand volumes and the decision to sell sand F.O.B. at the New Auburn plant reduced our operating cost per ton 82%, leading to $74.1 million in savings and resulting in an operating cost per ton (excluding depreciation) of $22.28 per ton produced in 2012. The balance of the increase was driven by the increased sales volume of northern Ottawa white frac sand that resulted from the construction and operation of SSS's New Auburn facility.

Costs associated with our Kosse, Texas facility decreased $12.8 million, primarily driven by a $13.6 million decrease in sales of Wisconsin sand from our Kosse facility. Costs associated with our Wisconsin facilities increased by $21.6 million. The 633% increase in northern Ottawa white frac sand volume sold from our Wisconsin operations resulted in $18.0 million of the increase in cost of goods sold, while increased transportation costs and unit production costs accounted for $1.2 million and $2.4 million of the increase in cost of goods sold, respectively. The increased production costs were

primarily driven by startup costs associated with the new Barron facility and increased processing costs during periods when customer order volumes called for product mix that could only be generated by forgoing optimal production conditions. The operating cost per ton, inclusive of freight and transportation services provided for our Wisconsin sand, was $22.8 million for the year ended December 31, 2012.

Selling, general and administrative expenses increased by $0.5 million, or 10%, to $5.5 million for the year ended December 31, 2012 compared to $5.0 million for the year ended December 31, 2011, primarily due to the increased hiring of individuals to manage the growth of the New Auburn and Barron operations.

Depreciation, depletion and amortization expense increased by $2.4 million, or 60%, to $6.4 million for the year ended December 31, 2012 compared to $4.0 million for the year ended December 31, 2011, primarily due to capital spending outlays related to the operation of SSS's New Auburn facility and the construction of the Barron facility.

Operating income increased by $29.2 million to $27.4 million for the year ended December 31, 2012 compared to a $1.8 million loss for the year ended December 31, 2011 as a result of increased sales volumes and a full 12 months of production from our New Auburn facility, which commenced operations in October 2011.

Interest expense increased by $8.8 million to $10.6 million for the year ended December 31, 2012 compared to $1.8 million for the year ended December 31, 2011 due to SSS's September 2012 senior loan refinancing, interest expense associated with SSS's second lien term loan with LBC Credit Partners, LP increasing from 0% to 12% (plus 6% payment in kind), $13.0 million in customer advances provided to us by our two largest customers and the capital lease agreement entered into with Fred Weber during the third quarter of 2011.

Provision for taxes was $81,000 for the year ended December 31, 2012, compared to $101,000 for the year ended December 31, 2011.

Net income increased by $20.6 million, to $16.8 million for the year ended December 31, 2012 compared to a net loss of $3.8 million for the year ended December 31, 2011 due to the factors noted above.

AEC's revenues increased by $208.1 million, or 60%, to $557.4 million for the year ended December 31, 2012 compared to $349.3 million for the year ended December 31, 2011. The average realized price of fuel sold in the year ended December 31, 2012 was essentially flat for the price per gallon of gasoline and increased by 3% in the price per gallon of diesel, respectively, compared to the year ended December 31, 2011 as market pricing for fuel was driven higher by economic factors. The

changes in average realized price of fuel resulted in a decrease of $1.0 million of gasoline revenue offset by a $5.4 million increase in diesel revenue. The volume of gasoline and diesel sold increased 79% and 32%, which resulted in increases of $140.5 million and $46.2 million in AEC's revenues, respectively. This increase was driven by growth of inbound transmix volume as well as the addition of several new wholesale customers, which was facilitated by improved liquidity that allowed management to drive greater volumes through AEC terminals. Other revenues, including excise taxes on fuel sales and fuel services, increased by $16.8 million, predominately as a result of higher excise taxes.

Cost of goods sold increased by $208.1 million, or 61%, to $548.0 million for the year ended December 31, 2012 compared to $339.9 million for the year ended December 31, 2011, primarily due to the overall increase in volume and higher supply costs on certain supply contracts that were renewed during 2011. The volume of petroleum products sold in the period increased by 59% compared to the prior comparable period primarily due to improved economic conditions and financing capacity to drive volumes. The average cost per unit of fuel sold in the period increased by 1% compared to the prior comparable period. As a percentage of revenues, cost of goods sold was 2% higher than the comparable prior year period. Revenues associated with excise taxes were offset one-for-one by excise tax cost of sales.

Selling, general and administrative expenses increased by $0.6 million, or 15%, to $4.6 million for the year ended December 31, 2012 compared to $4.0 million for the year ended December 31, 2011, primarily due to higher professional fees in connection with the settlement of litigation in December 2012.

Depreciation and amortization expense decreased by $0.2 million, or 7%, to $2.7 million for the year ended December 31, 2012 compared to $2.9 million for the year ended December 31, 2011.

Operating income decreased by $0.7 million, or 26%, to $2.0 million for the year ended December 31, 2012 compared to $2.7 million for the year ended December 31, 2011 primarily as a result of professional fees in connection with the settlement of litigation in December 2012.

Interest expense decreased by $0.7 million, or 47%, to $0.8 million for the year ended December 31, 2012 compared to $1.5 million for the year ended December 31, 2011 due to a refinancing of AEC's term loan facility and forgiveness of subordinated debt and seller notes which occurred in April 2011.

Net income decreased by $2.6 million to $0.5 million for the year ended December 31, 2012 compared to $3.1 million for the year ended December 31, 2011. The decrease in net income resulted from non-cash gains of $1.7 million from debt restructuring in 2011 that were not present in 2012, higher professional fees in 2012 in connection with the settlement of litigation in December 2012, and $0.8 million of litigation settlement expense in 2012.

SSS's revenues increased by $11.1 million, or 65%, to $28.2 million for the year ended December 31, 2011 compared to $17.1 million for the year ended December 31, 2010. Sales volumes for the 100 mesh frac sand produced at SSS's Kosse, Texas facility decreased by 1.5% from period to period, which resulted in a less than $0.1 million decrease in SSS's revenues. Sales volumes for our northern Ottawa white frac sand increased by 292% from period to period, with price holding flat over the period. The 108% total increase in 100 mesh and northern Ottawa white frac sand sales was primarily attributable to robust drilling activity and the commencement of SSS's New Auburn facility that came online in the fourth quarter of 2011. The commencement of operations at SSS's New Auburn facility accounted for 38% of total annual frac sand sales volume during 2011 and accounted for approximately $8.2 million of SSS's revenues during this period.

Across periods, 100 mesh prices increased approximately 6%, resulting in $0.2 million in incremental revenue. Spot market Wisconsin frac sand sales experienced an approximately 14% price increase, resulting in another $0.2 million in incremental revenue across periods. The remaining difference between the growth in revenues and growth in sales volume is attributable to our decision to sell material production volumes for delivery from the New Auburn facility, such that the customers bear shipping and logistics expenses.

SSS's cost of goods sold increased by $1.1 million, or 6%, to $19.3 million for the year ended December 31, 2011 compared to $18.2 million for the year ended December 31, 2010. Costs associated with the frac sand produced at our Kosse, Texas facility decreased $2.0 million due to improved operating procedures which led to nearly $14.0 million of savings driven primarily by fixed cost leverage offset by $12.0 million of incremental costs resulting from the 28% increase in total Kosse frac sand sales volumes. The balance of the increase was driven by the increased sales volume of northern Ottawa white frac sand that resulted from the construction and operation of SSS's New Auburn facility.

Selling, general and administrative expenses decreased by $1.2 million, or 19%, to $5.0 million for the year ended December 31, 2011 compared to $6.2 million for the year ended December 31, 2010, primarily due to a reduction in legal expenses resulting from a settlement of an outstanding litigation in 2010. Further savings were realized through the reduction of insurance premiums and through the elimination of third party consulting fees. The insurance and consulting related savings, however, were largely offset by increases in management compensation and by selling, general and administrative expenditures made in order to facilitate the construction and operation of our New Auburn facility.

Depreciation, depletion and amortization expense increased by $1.4 million, or 54%, to $4.0 million for the year ended December 31, 2011 compared to $2.6 million for the year ended December 31, 2010, primarily due to capital spending outlays related to the construction and startup of the New Auburn facility.

Operating loss decreased by $8.8 million, to ($1.8) million for the year ended December 31, 2011 compared to ($10.6) million for the year ended December 31, 2010 as a result of increased sales volumes and more efficient operations following the commencement of our New Auburn facility in October 2011.

Interest expense increased by $0.8 million, or 80%, to $1.8 million for the year ended December 31, 2011 compared to $1.0 million for the year ended December 30, 2010 due to interest payments associated with the $13.0 million in advances provided to us by our two largest customers and the capital lease agreement entered into with Fred Weber during the third quarter of 2011.

Provision for state and federal taxes increased $65,000 to $101,000 for the year ended December 31, 2011 compared to $36,000 for the year ended December 31, 2010. The increase resulted mainly from higher sales volumes for the year ended December 31, 2011.

Net loss decreased by $7.8 million, to ($3.8) million for the year ended December 31, 2011 compared to ($11.6) million for the year ended December 31, 2010 due to the factors noted above.

AEC's revenues increased by $104.8 million, or 43%, to $349.3 million for the year ended December 31, 2011 compared to $244.5 million for the year ended December 31, 2010. This increase in revenues was primarily driven by continued improvement in the overall U.S. economy combined with the addition of several new wholesale customers, which resulted in volume increases of 3% and 17% in gasoline and diesel, respectively, over the comparable prior year period. The volume growth in gasoline and diesel accounted for increases of $3.2 million and $15.6 million to AEC's revenues for the year ended December 31, 2011. Increases of 33% in the price per gallon of gasoline and 37% in the price per gallon of diesel resulted in increases of $44.4 million and $38.5 million to AEC's revenues, respectively, as demand for gasoline and diesel have continued to rebound from their recessionary lows. Other revenues, including excise taxes on fuel sales and fuel services, increased by $3.1 million.

Cost of goods sold increased by $100.8 million, or 42%, to $339.9 million for the year ended December 31, 2011 compared to $239.1 million for the year ended December 31, 2010, primarily due to an increase in sales volume across all business units. As a percentage of revenues, cost of goods sold was approximately in line with the comparable prior year period. Revenues associated with excise taxes were offset one-for-one by excise tax cost of sales.

Selling, general and administrative expenses increased by $0.2 million, or 5%, to $4.0 million for the year ended December 31, 2011 compared to $3.8 million for the year ended December 31, 2010, primarily due to a reduction in expenses relating to a dispute that was settled early in 2011 but that incurred legal and other costs in 2010.

Depreciation and amortization expense decreased by $0.2 million, or 6%, to $2.9 million for the year ended December 31, 2011 compared to $3.1 million for the year ended December 31, 2010, primarily due to the fact that certain assets became fully depreciated in 2010.

Operating income increased by $4.3 million to $2.7 million for the year ended December 31, 2011 compared to a $1.6 million loss for the year ended December 31, 2010 as a result of an increased volume of products sold.

Interest expense decreased by $2.4 million, or 62%, to $1.5 million for the year ended December 31, 2011 compared to $3.9 million for the year ended December 31, 2010 due to a refinancing of AEC's term loan facility and forgiveness of subordinated debt and seller notes in the second quarter of 2011.

Net income increased by $7.2 million to $3.1 million for the year ended December 31, 2011 compared to a net loss of $4.1 million for the year ended December 31, 2010 due to improvement of product volumes and the reduction of interest expense and gains realized on settlement of a trade dispute and debt restructuring.

The historical sources of liquidity for SSS and AEC have included cash generated from operations, investments by Insight Equity and other members, including management, and borrowings under their respective credit facilities.

The following table reflects cash flows for the applicable periods (amounts in thousands):

Operating activities consist primarily of net income adjusted for non-cash items, including depreciation, depletion and amortization and the effect of working capital changes.

Net cash provided by operating activities was $2.2 million for the year ended December 31, 2012 compared to $2.5 million in the year ended December 31, 2011. This $0.3 million decrease across periods was primarily attributable to the $20.6 million increase in net income offset by an increase in working capital. The increase in working capital was caused primarily by the $13.5 million relative increase in accounts receivable resulting from the 137% sales increase for the year ended December 31, 2012 relative to the year ended December 31, 2011. Additionally, cash used by inventory, other current assets, and trade payables and accrued expenses increased by $6.0 million, $0.1 million and $4.2 million, respectively, for the year ended December 31, 2012 relative to the year ended December 31, 2011. The growth in inventory was driven by the higher sales rate at the New Auburn facility as well as the buildup of a winter stockpile of wet sand prior to the commencement of operations at the Barron facility.

Investing activities consist primarily of property and equipment divestitures as well as capital expenditures for growth and maintenance.

Net cash used for investing activities was $37.7 million in the year ended December 31, 2012. Cash receipts were comprised of proceeds from the sales of excess property totaling $1.4 million offset by $39.1 million of capital expenditures outlaid primarily in connection with the construction of the Barron production facilities.

Net cash used in investing activities was $13.9 million in year ended December 31, 2011. This use of cash was primarily due to capital spending related to the construction of our New Auburn facility.

Financing activities consisted primarily of borrowings and repayments related to SSS's term loan facilities, its mezzanine loan facility and customer advances, as well as dividends to its parent company, fees and expenses paid in connection with our credit facilities and outstanding checks from our customers.

Net cash provided by financing activities was $31.1 million in the year ended December 31, 2012, compared to $14.0 million in the year ended December 31, 2011. This $17.1 million increase was primarily attributable to different cost and construction schedules for the New Auburn and Barron facilities in 2011 and 2012, respectively.

Net cash used in operating activities was $1.1 million for the year ended December 31, 2012 and $6.1 million for the year ended December 31, 2011. The change in the amount of cash used in operating activities primarily resulted from a smaller increase in working capital for the year ended December 31, 2012 relative to the year ended December 31, 2011. The smaller relative increase in operating working capital was due primarily to a $7.4 relative million increase in trade payables and accrued expenses as trade vendors extended more favorable credit terms, offset by a $1.0 million relative decrease in cash provided by inventory and other current assets.

Net cash used in investing activities was $1.4 million in the year ended December 31, 2012 compared to $0.8 million in the year ended December 31, 2011. This increase in cash used in investing activities is primarily attributable to an increase in capital spending on a one-time growth capital

expenditure related to AEC's vapor recovery unit of $0.1 million with the balance attributable to maintenance capital expenditures.

Net cash provided by financing activities was $1.8 million in the year ended December 31, 2012 compared to $5.6 million in the year ended December 31, 2011. The $1.8 million of net cash provided by financing activities during the year ended December 31, 2012 was primarily due to a draw on the revolving line of credit of $2.5 million, partially offset by a repayment of $1.2 million of long-term debt, with additional net proceeds from equipment loans of $0.5 million. Financing cash proceeds during the year ended December 31, 2011 were primarily due to a net equity investment of $4.0 million and revolving line of credit proceeds of $3.4 million, offset by equipment loan payments of $0.2 million, long-term debt payments of $0.9 million, cash distributed to a deconsolidated subsidiary of $0.3 million, a distribution of $0.1 million and financing costs of $0.3 million.

Operating activities consist primarily of net income adjusted for non-cash items, including depreciation, depletion and amortization and the effect of operating working capital changes.

Net cash provided by operating activities was $2.5 million for the year ended December 31, 2011 compared to ($1.3) million in the year ended December 31, 2010. This $3.8 million increase across periods was primarily due to a $7.8 million increase in net income that resulted primarily from increased sales volumes. This increase in net income was partially offset by a year over year change in operating working capital that was $4.6 million higher in the year ended December 31, 2011 relative to the year ended December 31, 2010. This increase in SSS's operating working capital was caused primarily by a $4.2 million increase in accounts receivable due to sales growth of 64% combined with a $4.6 million increase in inventory, offset by a $4.1 million increase in payables. The inventory increase resulted from a build-up due to the annual winter shut-down of the wet plant. The increase in payables primarily resulted from extended payment terms for wet sand.

Investing activities consist primarily of property and equipment divestitures as well as capital expenditures for growth and maintenance.

Net cash used in investing activities was $13.9 million in the year ended December 31, 2011 compared to $1.4 million in 2010. This increased use of cash was primarily required for capital expenditures of $13.5 million to design, permit and construct our New Auburn, Wisconsin production facility in 2011. For the year ended December 31, 2010, cash was used primarily for customary maintenance capital spending on our plant and heavy equipment, as well as $0.3 million investment in a new rotary dryer for SSS's Kosse, Texas operation.

Financing activities consisted primarily of borrowings and repayments related to SSS's term loan facilities and its mezzanine loan facility, as well as dividends to SSS's parent company, fees and expenses paid in connection with our credit facilities and outstanding checks from our customers.

Net cash provided by financing activities was $14.0 million in the year ended December 31, 2011, which consisted primarily of borrowings related to the $16.0 million in customer advances. Net cash

provided by financing activities for the year ended December 31, 2010 was $4.5 million, which consisted primarily of borrowings related to SSS's mezzanine loan facility and the term loan facilities.

Net cash used in operating activities was $6.1 million for the year ended December 31, 2011 compared to net cash provided by operating activities of $3.1 million in the year ended December 31, 2010. This $9.2 million increase of net cash used in operating activities across periods was primarily due to a $10.0 million decrease in accounts payable and accrued expenses as trade vendors reduced credit terms during the year ended December 31, 2011, a $3.4 million increase in accounts receivables and inventories, primarily driven by 43% sales growth, and $1.6 million less in income tax refunds offset by a $4.3 million improvement in operating income, which resulted from increases in volumes sold and prices of gasoline and diesel.

Net cash used in investing activities was $0.8 million in the year ended December 31, 2011 compared to $0.2 million in the year ended December 31, 2010. The increased use of cash was primarily caused by an increase of $0.6 million in capital spending for the year ended December 31, 2011 compared to the year ended December 31, 2010.

Net cash provided by financing activities was $5.6 million in the year ended December 31, 2011 compared to net cash used in financing activities in the year ended December 31, 2010, of $1.0 million. During 2011, $4.0 million of equity was invested in AEC by the ownership group. Additionally, $3.3 million of cash was generated from an increase in outstanding borrowings during 2011. AEC's improved liquidity was used to finance sales volume increases and throughput.

Growth capital expenditures are capital expenditures that we expect to increase, over the long term, our asset base, operating income or operating capacity. Growth capital expenditures will also include interest (and related fees) on debt incurred to finance all or any portion of the construction of such capital improvement in respect of the period that commences when we enter into a binding obligation to commence construction of a capital improvement and ending on the earlier to occur of the date any such capital improvement commences commercial service and the date that it is abandoned or disposed of. Capital expenditures made solely for investment purposes will not be considered growth capital expenditures. The primary purpose of growth capital expenditures is to build or acquire assets that will increase our distributions per unit in a manner that is expected to be accretive to our unitholders. Growth capital expenditures for the year ended December 31, 2012 were $37.8 million and $0.1 million for SSS and AEC, respectively. Growth capital expenditures for the year ended December 31, 2011 were $13.5 million and $0.7 million for SSS and AEC, respectively.

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 governs SSS's $10.0 million revolving credit facility and its $50.0 million senior term loan facility, each of which bear an interest rate of LIBOR plus 375 basis points as of December 31, 2012 and has a maturity date of September 7, 2016. As of December 31, 2012, SSS had outstanding borrowings of $8.3 million under its revolving credit facility and $48.5 million under its senior term loan facility, all of which carried an interest rate of 3.97% per annum. Approximately $32.3 million of the borrowings were used to repay amounts outstanding under SSS's term loan due 2014 with LBC Credit Partners, LP and the remainder for general corporate purposes, primarily to fund the construction of the new facilities in Barron County, Wisconsin. Substantially all of SSS's property is pledged as collateral under the first lien credit agreement and the second lien and third lien credit agreements discussed below. The first lien credit agreement contains customary covenants, including, among others, covenants that restrict SSS's ability to make or limit certain payments, distributions, acquisitions, loans, or investments, incur certain indebtedness or create certain liens on its assets. As of December 31, 2012, SSS was in compliance with its debt covenants under the first lien credit agreement. We expect to repay all amounts outstanding under the revolving credit and senior term loan facilities in full at the closing of this 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. The credit agreement governs SSS's second lien term loan, which matures on March 7, 2017. As of December 31, 2012, SSS had $41.8 million in outstanding borrowings bearing a cash interest rate of 12% per annum and an additional 6% per annum of PIK interest paid through an increase in the outstanding principal amount of the loan. 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 will bear cash interest at a rate of 12% per annum and PIK interest at a rate of 6% per annum until March 2013, at which point all interest converts to PIK. The second lien credit agreement contains affirmative, negative and various financial covenants under which SSS is obligated. As of December 31, 2012, SSS was in compliance with its debt covenants under the second lien credit agreement. We also expect to repay the second lien term loan in full at the closing of this 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 governs SSS's third lien term loan, which matures on September 7, 2017 and bears interest at a rate of 0% per annum. The third lien credit agreement contains affirmative, negative and various financial covenants under which SSS is obligated. As of December 31, 2012, SSS was in compliance with its debt covenants under the third lien credit agreement. We also expect to repay the third lien term loan in full at the closing of this offering.

As of December 31, 2012, SSS had a total of approximately $103.9 million of indebtedness outstanding under these arrangements.

On May 16, 2008, AEC Holdings entered into a credit agreement with a syndicate of lenders led by Citibank, N.A. The credit facility, as amended, matures on April 1, 2015, and, as of December 31, 2012, is composed of a $21.3 million term loan facility and a $15.0 million revolving credit facility, which includes a sub-limit of up to $5.0 million for letters of credit. As of December 31, 2012, the revolving credit facility balance outstanding was $13.0 million and the term loan balance was $18.4 million. All of AEC Holdings' property is pledged as collateral under this credit facility. The terms of the credit facility contain customary covenants, including, among others, those that restrict

AEC Holdings' ability to make or limit certain payments, distributions, acquisitions, loans, or investments, incur certain indebtedness or create certain liens on AEC Holdings' assets. As of December 31, 2011 and December 31, 2012, AEC Holdings was in compliance with the covenants in its existing credit facility. We expect to repay all amounts outstanding under the revolving credit and senior term loan facilities in full at the closing of this offering.

On November 18, 2010, Direct Fuels refinanced its existing revolving credit facility and entered into a revolving credit, term loan and security agreement with a syndicate of lenders led by PNC Bank, National Association. The credit facility, as amended, matures on November 28, 2013, and, as of December 31, 2011, was composed of a $9.7 million term loan facility and a $14.0 million revolving credit facility, which includes a sub-limit of up to $5.0 million for letters of credit. On October 22, 2012, Direct Fuels amended its revolving credit, term loan and security agreement with PNC Bank, National Association. The credit facility, as amended, matures on November 28, 2013, and, as of December 31, 2012, is composed of a $16.7 million term loan facility and a $14.0 million revolving credit facility, which includes a sub-limit of $5.0 million for letters of credit. As of December 31, 2012, the term loan facility and revolving credit facility balances outstanding were $16.7 million and $0.4 million, respectively. Substantially all of Direct Fuels' property is pledged as collateral under this credit facility. The terms of the credit facility contain customary covenants, including, among others, covenants that restrict Direct Fuels' ability to make or limit certain payments, distributions, acquisitions, loans or investments, incur certain indebtedness, or create certain liens on Direct Fuels' assets. As of December 31, 2012 Direct Fuels was in compliance with the covenants in its existing credit facility. We expect to repay all amounts outstanding under the revolving credit and senior term loan facilities in full at the closing of this offering.

There are no contingencies which, in the opinion of management, are likely to have a material impact on the financial condition, liquidity or reported results of any of SSS or AEC.

A summary of SSS's contractual obligations as of December 31, 2012 is provided in the following table.

A summary of AEC's contractual obligations as of December 31, 2012 is provided in the following table.

SSS is exposed to market risk with respect to the pricing that it receives for its 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 may 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, with limitation, in response to certain cost increases. As a result, SSS's realized prices for its frac sand may not grow at rates consistent with broader industry pricing. During periods of rapid price growth, SSS's

realized prices may grow more slowly than those of competitors, and during periods of price decline, its realized prices may outperform industry averages. SSS does not enter into commodity price hedging agreements with respect to its sand production.

AEC is exposed to market risk with respect to the pricing that it charges for its refined fuels products and that it pays for its transmix, wholesale fuel and other feedstocks. Realized margins for AEC's refined fuel products are determined by the relationship, between the prices it charges for fuel and the prices it pays for transmix, wholesale fuel and other feedstocks. AEC purchases its 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 AEC's purchases are generally set on the day that it purchases the products. AEC typically sells its fuel products within seven to ten days of its supply purchases at then prevailing market prices. If the market price for AEC's fuel products declines during this period or generally does not increase commensurate with any increases in its supply and processing costs, AEC's margins will fall and the amount of cash AEC will have available for distribution will decrease. In addition, because AEC values its inventory at the lower of cost or market value, if the market value of our inventory were to decline to an amount less than AEC's cost, it 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, AEC's inventory valuation methodology may result in decreases in its reported net income.

AEC utilizes financial hedging arrangements whereby it hedges a portion of its gasoline and diesel inventory, which reduces its commodity price exposure on some of its activities.

The derivative commodity instruments utilized by AEC consist mainly of futures traded on the New York Mercantile Exchange. AEC does not designate these commodity instruments as cash flow hedges under Accounting Standards Codification (ASC) 815, Derivatives and Hedging. As a result, AEC records derivatives at fair value on the consolidated balance sheet with resulting gains and losses reflected in cost of fuel as reported in the consolidated statement of operations. AEC's derivative commodity instruments serve the same risk management purpose whether designated as a cash flow hedge or not. AEC derives 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.

SSS and AEC are exposed to various market risks, including changes in interest rates. Market risk related to interest rates is the potential loss arising from adverse changes in interest rates. We do not believe that changes in interest rates have a material impact on the financial position or results of operations of SSS and AEC during periods covered by the financial statements included in this prospectus.

SSS manages its exposure to changing interest rates through the use of fixed rate debt. As of December 31, 2012, approximately 45% of SSS's total indebtedness consisted of fixed rate debt.

AEC is exposed to fluctuations in interest rates since its borrowings are variable rate debt. AEC enters into certain interest rate swap agreements in accordance with its risk management strategy. These agreements do not meet the criteria for hedge accounting, however, these agreements do have the economic impact of mitigating interest rate risk. The interest rate swap agreements are accounted for on a mark-to-market basis through current earnings even though they were not acquired for trading purposes. As of December 31, 2012 and 2011, AEC was not a party to any interest rate swap agreements. AEC recognized derivative contract gains of $0 and $0.2 million in the consolidated statement of operations for the years ended December 31, 2012 and 2011, respectively.

AEC is subject to risk of losses resulting from nonpayment or nonperformance by certain counterparties to interest and commodity derivative interests. The credit exposure related to interest and commodity derivative instruments is represented by the fair value of the asset position (i.e., the fair value of expected future receipts) at the reporting date. Should the creditworthiness of one or more of the counterparties decline, AEC's ability to mitigate nonperformance risk is limited to a counterparty agreeing to either a voluntary termination and subsequent cash settlement or a novation of the derivative contract to a third party. In the event of a counterparty default, AEC may sustain a loss which could negatively impact cash receipts.

SSS and AEC are subject to risks of loss resulting from nonpayment or nonperformance by their customers. Each of SSS and AEC examines the creditworthiness of third-party customers to whom credit is extended and manages exposure to credit risk through credit analysis, credit approval, credit limits and monitoring procedures. The top three customers of SSS accounted for 42%, 28%, and 13% respectively of SSS's revenue for the year ended December 31, 2012. AEC's most significant customer accounted for 16% of revenue for the year ended December 31, 2012.

Listed below are the accounting policies we believe are critical to our discussion and analysis of financial condition and results of operations, and that we believe are critical to the understanding of our operations.

In general, we recognize revenue from customers when all of the following criteria are met:

In our Sand segment, revenue is generally recognized when sand leaves our plants. The sand is generally transported via railcars or trucking companies hired by the customer. Our revenues are primarily a function of the price per ton realized and the volumes sold. The majority of our revenues from our New Auburn facility are currently realized through take-or-pay supply agreements with two large well capitalized oilfield services companies whereas the majority of revenues at our Barron 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 may 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. These agreements define, among other commitments, the volume of product that our customers must purchase, the volume of product that we must provide and the price that we will charge and that our customers will pay for each ton of contracted product. Prices under all of our supply 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 not allowed

to carry forward minimum quantities under the terms of the contract, we recognize revenues to the extent of the minimum contracted quantity, assuming payment has been received or is reasonably assured. If deficiencies can be made up, receipts in excess of actual sales are recognized as deferred revenues until production is actually taken or the right to make up deficiencies expires. As a result, there are uncertainties as to when and whether the requirements for the recognition of revenue from our take-or-pay arrangements will be satisfied and, in determining whether or when to recognize revenue under our take-or-pay contracts, management makes judgments regarding a customer's ability to pay and whether a customer will purchase less than the contracted volume.

In our Fuel Processing and Distribution segment, revenue is generally recognized when fuel is loaded onto a customer-provided truck. We recognize revenue related to terminal and reclamation 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 and determinable.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions. These estimates and assumptions affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements, as well as the reported amounts of income and expenses during the reporting period. Actual results could differ from these estimates. The accounting estimates that require the most significant, difficult and subjective judgment include:

We make every effort to record actual volume and price data, however, there may be times where we need to make use of estimates for certain revenues and expenses. If the assumptions underlying our estimates prove to be substantially incorrect, it could result in material adjustments in results of operation.

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. All of our property, plant and equipment is depreciated 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. At the time we place our assets in-service, we believe such assumptions are reasonable; however, circumstances may develop that would cause us to change these assumptions, which would change our depreciation amounts prospectively. Examples of such circumstances include:

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

We follow the provisions of Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("ASC") 410-20-05, Accounting for Asset Retirement Obligations, or ASC 410-20-05. ASC 410-20-05 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.

Under ASC 410-20-05, SSS recognized an estimated liability for costs associated with the abandonment of sand mining properties. 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 increased carrying value is depleted using the unit-of-production 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. For the liability recognized, SSS utilized a discounted rate reflecting management's best estimate of its credit-adjusted risk-free rate. Revisions to the liability could occur due to changes in the estimated costs, changes in the mine's economic life or if federal or state regulators enact new requirements regarding the abandonment of mine sites.

In accordance with FASB ASC Topic 360, Accounting for the Impairment or Disposal of Long-Lived Assets, 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.

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.

In May 2011, FASB issued Accounting Standards Update (ASU) No. 2011-04, Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs, or ASU 2011-04. ASU 2011-04 changes some fair value measurement principles under GAAP, including a change in the valuation premise and the application of premiums and discounts. It also contains some new disclosure requirements under GAAP. It is effective for interim and annual periods beginning after December 15, 2011. The adoption of this new guidance did not have a significant impact on our financial position, cash flows or results of operations.

Section 107 of the JOBS Act provides that an "emerging growth company" can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act for complying with new or revised accounting standards. In other words, an "emerging growth company" can delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. We are electing to delay such adoption of new or revised accounting standards, and as a result, we may not comply with new or revised accounting standards on the relevant dates on which adoption of such standards is required for non-emerging growth companies. As a result of such election, our financial statements may not be comparable to the financial statements of other public companies. We may take advantage of these reporting exemptions until we are no longer an "emerging growth company."

Prior to the completion of this offering, we and SSS and AEC, which together constitute our predecessor for accounting purposes, have been private entities, with limited accounting personnel to adequately execute our accounting processes and limited other supervisory resources with which to address our internal control over financial reporting. As such, both SSS and AEC have failed in the past to maintain an effective control environment to ensure that the design and execution of our controls has consistently resulted in effective review of our financial statements and supervision by appropriate individuals.

We and our independent registered public accounting firm concluded that these control deficiencies constituted material weaknesses in our control environment. Under standards established by the Public Company Accounting Oversight Board, a material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected and corrected on a timely basis.

AEC remediated the material weakness identified with respect to its 2010 audit, primarily through the implementation of logistical and security controls with respect to its information technology, and that material weakness did not recur in 2011 or 2012.

SSS remediated the material weakness identified with respect to its 2010 and 2011 audit, primarily through the hiring of more senior and experienced accounting and finance personnel, and that material weakness did not recur in 2012.

Upon the completion of this offering, we will become subject to the public reporting requirements of the Securities Exchange Act of 1934, as amended, or the Exchange Act. Section 404 of the Exchange Act will require us to annually review and report on, and our independent registered public accounting firm to attest to, the effectiveness of our internal controls over financial reporting. Although we will be required to disclose changes made in our internal control and procedures on a quarterly basis, we will not be required to make our first annual assessment of our internal control over financial reporting pursuant to Section 404 until the fiscal year ending December 31, 2013. Our independent registered public accounting firm will not be required to formally attest to the effectiveness of our internal control over financial reporting until the later of the year following our first annual report required to be filed with the SEC or the date we are no longer an "emerging growth company," which may be up to five full fiscal years following this offering.

The commercial silica industry consists of businesses that are involved in the mining, processing and sale of commercial silica. Commercial silica, also referred to as "silica," "industrial sand and gravel," "silica sand" and "quartz sand," is a term applied to sands and gravels containing a high percentage of silica (also known as silicon dioxide or SiO₂) in the form of quartz. Commercial silica deposits occur throughout the United States, but mines and processing facilities are typically located near developed rail infrastructure, which facilitates access to markets. Other factors affecting the feasibility of commercial silica production include deposit composition, product quality specifications, land-use and environmental regulation, including permitting requirements, access to electricity, natural gas and water and a producer's expertise and know-how.

The low relative cost and special properties of commercial silica—chemistry, purity, grain size, color, inertness, hardness and resistance to high temperatures—make it critical to a variety of industries and end-use markets, including oil and natural gas recovery, glass production, the manufacturing of building products, the production of molds for metal castings and in the fillers and extenders end-use markets. In particular, commercial silica is a key input in the hydraulic fracturing techniques used in the development of unconventional oil and natural gas resource basins.

Advances in unconventional oil and natural gas extraction techniques, such as horizontal drilling and hydraulic fracturing, have allowed for significantly greater extraction of oil and natural gas trapped within unconventional resource basins such as shale rock. The hydraulic fracturing process consists of pumping fluids down an oil or natural gas well at pressures sufficient to create fractures in the hydrocarbon-bearing rock formation in order to increase the flow rate of hydrocarbons from the well. A granular material, called proppant, is suspended and transported in the fluid and fills the fracture, "propping" it open once high-pressure pumping stops. The proppant-filled fracture creates a conductive channel through which the hydrocarbons can flow more freely from the formation to the well and then to the surface. Proppants therefore perform the vital function of promoting the flow, or conductivity, of hydrocarbons over a well's productive life.

There are three primary types of proppant that can be utilized in the hydraulic fracturing process: commercial silica (known as frac sand), resin-coated sand and ceramic. Proppant typically costs between $30 to $100 per ton for frac sand and up to $500 to $700 per ton for the highest grade ceramics, with pricing for coated sand selling at a slight discount relative to ceramics. Because the price of proppant represents a significant cost to completing an oil or natural gas well, particularly for synthetic proppants, such as ceramics and resin coated sand, operators are price sensitive when selecting which proppant to use when completing a well. During periods of depressed energy prices, some operators may settle for lower cost and lower conductivity frac sands even though well productivity may be impacted.

Frac sand represents the lowest cost and largest volume of proppant supplied to pressure pumping companies and operators. According to the PropTester® Report, frac sand (and sand substrate used for resin coating) represented approximately 90% of all primary proppant types supplied in 2012. In addition, we believe operators are migrating to high-quality frac sand as their proppant of choice in most unconventional resource developments in circumstances where frac sand will yield results equivalent to higher priced synthetic alternatives. Therefore, since 2000, increased demand for frac sand, particularly coarser sand (such as 16/30, 20/40 and 30/50 mesh), and constrained supply increases have resulted in favorable pricing trends for frac sand producers.

Reflecting these industry dynamics, the PropTester® Report estimates the 2012 global frac sand market consumption (and sand substrate used for resin coating) at approximately 31.8 million tons, an increase of approximately 3.2 million tons (or 11.2%) compared to approximately 28.6 million tons in 2011. The United States is the single largest consumer of proppants, followed by Canada. Within the United States, the 2013 USGS Minerals Yearbook Summary, published February 2013, reports that 25.7 million tons of frac sand were consumed in the United States in 2012 compared to 16.3 million tons in 2011, a 58% increase. According to the USGS, frac sand consumption increased approximately 85% in 2010 to approximately 13.3 million tons, compared to approximately 7.2 million tons of frac sand produced in 2009. The following chart depicts historical global and U.S. consumption of frac sand in the oil and gas proppants market from 2000 through 2011.

Because the selection of a particular proppant can account for a meaningful portion of the cost to complete an oil or natural gas well and, therefore, the economics of a well, operators must balance concerns of cost, availability and performance when selecting which type of proppant to use in their drilling operations. Frac sand must meet stringent technical specifications set forth by ISO and API including, among others, coarseness, crush resistance, conductivity, sphericity, acid solubility, purity and turbidity. Certain of these characteristics are of prominent importance because they influence both availability and pricing of frac sand and can have a significant impact on the ultimate production rate and profitability of a well. These key characteristics are coarseness, crush resistance and conductivity.

In fracturing a well, operators must select a proppant that is transportable into the fracture, is compatible with frac and wellbore fluids, permits acceptable cleanup of frac fluids and can resist flowback. In addition, the proppant must be thermally stable, chemically inert, environmentally benign and readily available in adequate quantities. Frac sands that meet these specifications are typically mined from poorly cemented Cambrian and Ordovician sandstones and from unconsolidated alluvial sands locally derived from these sandstones.

High-quality northern Ottawa white frac sand resources are largely limited to select areas, predominantly the upper Midwest United States. The State of Wisconsin has abundant resources of high-quality, northern Ottawa white frac sands found in marine sandstones of the Cambrian age that are desirable for use in hydraulic fracturing. Several geologic formations located in Wisconsin contain silica sands with favorable characteristics for use as a proppant: nearly pure quartz content, highly spherical shape, uniformity and high crush resistance. While most known ore bodies possess a heavy concentration of 40/70 mesh, a limited number of these Wisconsin deposits possess generally coarser sand formations, with less of a concentration of 40/70 mesh, and therefore are well-suited to optimize production in oil- and liquids-rich areas and currently command premium market pricing in comparison to other frac sands, such as brown and southern white sand found in Arkansas, Missouri, Oklahoma and Texas. In addition, Wisconsin's silica sand resources are generally found near the surface of the formations, which lowers the cost of mining the sand relative to sand that is found deeper under the surface of the formations. The principal areas of interest in the state for sand mining have been in western Wisconsin, with the coarser deposits located in the northernmost locations, including the deposits mined by us.

The locations identified on the map below detail the outcrop areas of Cambrian quartz sandstones found primarily in Wisconsin.

The primary factors currently influencing demand for frac sand in the United States are the level of horizontal drilling activity by exploration and production companies and the level of associated hydraulic fracturing services, specifically the volume of proppant pumped per fracturing stage and per well on an aggregate basis. Since late 2010, there has been a significant 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. According to the Freedonia Report, North American raw frac sand demand, by weight, grew 29% per year from 2006 to 2011 and is expected to grow 7.3% per year from 2011 to 2016. The following chart illustrates historical and forecasted proppant demand and Raw Frac Sand prices for certain years from 2001 to 2021.

The following trends have contributed to the significant increase in demand for frac sand.

Ongoing and increased exploration and production of unconventional oil and natural gas fields has led to increased demand for hydraulic fracturing services and frac sand. Two technologies—horizontal drilling and hydraulic fracturing—are critical to recovering oil and natural gas from unconventional resource formations. These activities require material inputs of frac sand and other proppants. Whereas a traditional vertical well typically may require 50 to 250 tons of proppant, a horizontal well typically involves high-volume proppant stimulation completions often requiring 1,500 to 3,000 tons or more. The following chart identifies trends in the number of horizontal drilling rigs from 2004 to 2012.

Advances in drilling and completion technologies have made the development of many unconventional resource formations, such as oil and natural gas shales, economically attractive. In addition, horizontal wells have become longer and more complex, which has intensified demand for frac sand and other proppants. Technological improvements have led to this increase in demand as a result of:

In addition to the overall increase in the number of horizontal drilling rigs, over the last four years, there has been a significant shift in drilling activity in the United States from dry gas formations to oil- and liquids-rich formations, which has led to a corresponding increase in demand for coarser frac sands that facilitate the conductivity of oil- and liquids-rich drilling applications. For example, according to the North American rig count data published by Baker Hughes Inc., at January 4, 2008, there were approximately 300 rigs drilling for oil and over 1,450 rigs drilling for natural gas in the United States. At March 1, 2013, there were over 1,337 drilling rigs operating in oil-and liquids-rich areas of the United States, while the natural gas rig count had declined to approximately 420. The following chart illustrates the recent trends depicting the increase in the oil-related rig count as compared to the natural gas-related rig count.

The trend towards oil-related rigs indicates an ongoing demand increase for coarser proppants as oil, being a coarser molecule than natural gas, often requires a larger proppant to effectively and economically drain a reservoir. In general, oil- and liquids-rich formations require a higher percentage of coarser proppants such as 16/30, 20/40 and 30/50 mesh, whereas many unconventional dry natural gas formations are fracture stimulated with large volumes of fine grained 40/70 and 100 mesh proppants. The increased drilling activity in oil- and liquids-rich formations in the United States is primarily taking place in unconventional shale plays, such as the Eagle Ford, Bakken, Niobrara and Utica Shales, and other unconventional formations, such as the Mississippian formation in Oklahoma. Although the exploration and production industry is cyclical and oil prices have historically been volatile, we believe that many of the oil- and liquids-rich plays are economically attractive at prices substantially below the current prevailing prices for oil and liquids-rich gas. We believe this should provide continued and growing opportunities for drilling activity in oil- and liquids-rich formations and continued growth in demand for coarser frac sands.

Frac sand deposits are formed from a variety of sedimentary processes and have distinct characteristics that range from hard sandstone rock to loose, unconsolidated dune sands. While the specific extraction method utilized depends primarily on the deposit composition, most frac sand is mined using conventional open-pit bench extraction methods and begins after clearing the deposit of any overlaying soil and organic matter. The sand deposit composition and chemical purity also dictate the processing methods and equipment utilized. For example, broken rock from a sandstone deposit may require one, two or three stages of crushing to liberate the sand grains required for most markets. Unconsolidated deposits may require little or no crushing, as sand grains are not tightly cemented together.

After extracting the ore, the sand is washed with water to remove fine impurities such as clay and organic particles. In some deposits, these fine contaminants or impurities are tightly bonded to the surface of the sand grain and require attrition scrubbing to be removed. Other deposits require the use of flotation to collect and separate contaminants from the sand. When these contaminants are weakly magnetic, special high intensity magnets may be utilized in the process to improve the purity of the final frac sand product. After the sand has been washed, most output is dried prior to sale. In order to meet the requirements of the oilfield services industry, frac sand is dried until it contains no moisture. The final step in the production process involves the classification of frac sand according to its coarseness.

Most frac sand is shipped in bulk to customers by truck or rail. The frac sand industry has experienced a shift away from truck to rail as service companies are more willing to invest in transportation infrastructure in order to obtain access to high-end proppants in an effort to improve hydraulic fracturing production. In 2011, the frac sand industry experienced a shortage of railcars needed to haul frac sand due to increased demand. As of the fourth quarter of 2012, the industry is adequately equipped from a rail car supply perspective, but shipment volumes remain constrained by the lack of frac sand transloading and storage infrastructure available in close proximity to highly active unconventional oil and natural gas basins. As more transloading and storage infrastructure comes online during 2013, decreased rail transit times should further alleviate rail related supply constraints.

Transportation cost represents a significant portion of the overall delivered product cost of frac sand. The majority of sand production transported by truck is sold within approximately 200 miles of the producing facility because the cost of transportation beyond that distance generally makes the frac sand uneconomic to the customer. This limitation emphasizes the importance of rail access for low-cost delivery outside of the 200-mile trucking radius. Therefore, locating a frac sand production facility near rail infrastructure is one of the most important considerations for producers and customers. Despite the expense, transporting frac sand for use in oil and natural gas recovery by rail over long distances is economically feasible because of its importance in extracting a high-value end product, particularly in high commodity price cycles.

Supplies of frac sand have historically failed to keep pace with demand. Furthermore, recent increases in frac sand capacity have largely consisted of 30/50 and finer mesh sizes; however, coarser sands, such as 20/40, have been a primary focus for most new hydraulic fracturing activity for oil and liquids-rich gas wells. As a result of the economic downturn of 2008 and 2009, there was no significant expansion of domestic frac sand production. The increasing trend in oil- and liquids-rich drilling activity and the corresponding increase in demand for frac sand severely strained the available supply of high-quality coarser frac sands (such as 16/30, 20/40 and 30/50 mesh) in 2011 and led to significant efforts to develop additional sand reserves and associated processing facilities. While both large and small producers have implemented or announced some supply expansions, several key constraints to increasing production on an industry-wide basis remain, including:

Since 2000, the increased demand for frac sand from customers in the oil and gas proppants market and limited supply increases have resulted in favorable pricing trends for frac sand producers. According to the Freedonia Report, frac sand prices increased at an average annual rate of 4.7% from 2001 to 2011. In addition, the shift of drilling activity in the United States 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 risen more than the prices for finer frac sand since 2008. The U.S. Bureau of Labor Statistics Producer Price Index for Industrial Sand Mining—Secondary Products, which includes frac sand, suggests that prices rose 2.4% during the twelve month period ended December 31, 2012. Certain data points indicate that spot prices for domestic orders of frac sand have declined in recent months; however, prices have increased in northwest Canada and other international markets. We currently believe that the market will support contracts for frac sand at prices similar to our current contracts, and that our revenues will be further supplemented through logistics and supply chain services.

The primary driver of activity and earnings in our Fuel Processing and Distribution segment is our transmix operations. The transmix industry consists of businesses that process and separate transportation mixture, which is the liquid interface, or fuel mixture, that forms when multiple types of petroleum are transported sequentially through a pipeline. Pipeline operators send large batches of different fuel products (such as gasoline, diesel and jet fuel) through the same pipeline, in sequence, to receiving terminals. Generally, product batches are placed directly against each other, without any practical means of keeping them separated. Some mixing of fuels occurs at the interface of different batches in a pipeline. The actual volume of mixed material generated depends on a number of physical parameters including product sequencing decisions made by pipeline operators and the flow rate of the pipeline. Transmix can also be generated when the wrong type of refined fuel product is put in a tank or pipeline creating fuel that no longer meets the appropriate specifications. This situation, called a "cross dump," generates much less transmix than the mixing of different fuels in refined product pipelines.

As the transmix reaches the receiving terminal, it is "cut-out" of the refined products pipeline and transferred to a dedicated storage tank at the terminal. Each transmix "cut" consists of some mixture of gasoline, diesel, jet fuel or other previously certified petroleum product. Pipeline operators focus on maintaining a balance between minimizing transmix and ensuring that terminal operators never exhaust their supply of refined products. Since fuel terminals generally do not have sufficient storage for more than a few days' worth of sales, pipeline operators must make frequent changes between the various refined products that they transport. The chart below illustrates how different varieties of fuel are transported through pipelines and how transmix is generated as a by-product of those shipments.

There are three ways that transmix can be re-introduced into the pool of refined products in order to meet applicable industry standards. First, it can be blended into refined products with no further processing. Because blending transmix into refined products can create potential quality problems, only a limited portion of the transmix that is produced is blended in this manner. Second, transmix can be sent to a refinery, blended with crude oil and then separated into refined products through the crude oil refining process. Major refineries, however, prefer not to process transmix because their refining capacity is typically constrained. Additionally, processing transmix is less economical for them than processing crude oil due to relatively lower volumes, higher acquisition costs, decreased operating efficiencies and concerns over additives in the transmix supply that may impact the life of the catalysts. Finally, transmix can be sold to a specialty transmix processor, such as our subsidiaries Direct Fuels and AEC, for further processing into refined products. We believe this last option is the most efficient means of handling transmix and that producers of transmix generally choose to sell their product to specialty transmix processors.

As the chart below illustrates, total consumption of liquid fuels in the United States, including both fossil fuels and biofuels, is expected to remain relatively stable from 2011 (19.1 million barrels per day) to 2035 (to 19.9 million barrels per day), according to the EIA. The transportation sector is expected to continue to account for the largest percentage of demand for liquid fuels (as measured by energy content), accounting for approximately 71% and 72% of total liquids consumption in 2011 and in 2035, respectively.

Source: Annual Energy Outlook 2012 published by the Energy Information Administration in June 2012

We believe that transmix processing volumes generally increase or decrease at approximately the same rate as liquid fuel consumption. Transmix volume is also driven by changes in governmental regulations. For example, transmix volumes increased significantly in 2006 due to regulations promulgated by the EPA in mid-2006 that required a reduction in the sulfur content of diesel fuel. In particular, the maximum allowable sulfur content for on-road diesel fuel was reduced 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. There is no specific transition date required for locomotive and marine diesel; 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. Other than the sulfur standards for diesel fuel, we believe there are currently no pending regulatory changes that will impact the volume of transmix produced in the United States.

Producers of transmix, which are primarily pipeline and fuel terminal operators, generally evaluate processors of transmix based on several criteria, the most important of which are price and service. Price is principally driven by the cost of transporting the transmix to the processor. Transmix producers that are connected to outbound refined product pipelines have more alternatives for finding transmix processors and, as a result, are generally able to negotiate more favorable transmix pricing terms. Many producers of transmix, however, must rely on trucks to transport their transmix. The high cost of moving transmix by truck limits the distance that the product can be economically delivered to a processor. In addition, terminal operators have limited storage available for transmix. If transmix storage tanks become full, then it becomes necessary to shut the pipeline down or transfer transmix into a finished product tank, which results in the need to downgrade a substantial amount of finished product. Therefore, transmix producers typically select processors that demonstrate an ability to handle large volumes of transmix with little or no lead time.

Apart from the importance of price, which is driven primarily by geographic location, and demonstrated ability to service supplier needs, other effective barriers to entry exist in the transmix processing business. New transmix processors are difficult to establish because they require extensive municipal, state and federal air and land-use permits, tank storage, access to inexpensive feedstocks, economical access to bring in octane-boosting additives and loading racks to transfer the refined products onto trucks. The map below shows the 19 dedicated transmix processing plants that we believe were operating in the United States as of December 2012.

Transmix processors have two alternatives for selling their finished product. The first is to sell it in the local market across a truck rack. The second is to store large batches and then send it via pipeline, rail, truck or barge into other markets for sale. The first alternative is generally preferred because fewer intermediaries are involved, which reduces cost. Additionally, product can be sold as soon as it is produced, which significantly reduces the amount of inventory of finished product stored locally. As a result, the most favorable location for a transmix processing facility is at a bulk fuel terminal with a truck loading rack in a large metropolitan area.

This method of processing and selling transmix can be enhanced in several ways. First, the supply of refined product from the transmix operation can be supplemented with additional refined products purchased on a wholesale basis. Second, many sellers of refined fuels do not want to make the significant investment required to purchase a bulk fuel terminal and would rather secure the right to sell their product through bulk fuel terminals owned and operated by companies like ours. These strategies facilitate a transmix processor's ability to attract and retain customers while also enhancing returns on invested capital.

Bulk fuel terminals require several attributes to be successful, including connectivity to supply, accessibility to end-use markets and storage capacity. A bulk fuel terminal's connectivity to multiple sources of supply helps ensure reliable and economic sources of inbound product. The most common and economical means of bringing supply into bulk fuel terminals are via pipeline and barge, although some bulk fuel terminals are also set up to receive product via rail, truck and barge. In addition, a bulk fuel terminal's close proximity to the ultimate end-use market is important because transportation costs are a significant component of overall fuel costs. In addition, maintaining loading racks that can transfer large quantities of fuel quickly and efficiently reduces idle time while product is loaded. Furthermore, bulk fuel terminals require sufficient product storage capacity in order to maintain sufficient inventory levels and meet customers' demands for finished product.

We conduct our Sand operations through our subsidiary SSS and our Fuel Processing and Distribution operations through our subsidiaries Direct Fuels and AEC. Our Sand segment is expanding rapidly and we expect it to continue to provide a significant majority of our cash available for distribution in the future.

Our Sand segment consists of facilities in New Auburn, Wisconsin, Barron County, Wisconsin and Kosse, Texas that are optimized to exploit the reserve profile in place at each location and produce high-quality frac sand. Our Wisconsin sand reserves at our New Auburn and Barron County facilities provide 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 Ottawa white deposits located in Wisconsin's Jordan, St. Peter and Wonewoc formations. According to the PropTester® Report, many of the northern Ottawa white deposits in these formations contain less than 30% 40 mesh and coarser substrate. However, our sample boring data has 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, which along with other coarse sands is currently subject to high demand from our customers. 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 little 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 New Auburn sand facility has on-site rail car loading facilities, which are designed to accommodate approximately 20% more volume daily than the maximum daily output of our dry plant, and 4.5 miles of existing rail track that connects our facility to the Union Pacific rail line and provides us with direct shipping access to all of the major shale basins 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. 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 our New Auburn facility. We have enclosed the facility, giving us the ability to dry and load approximately 40 rail cars of frac sand per day independent of outside weather conditions. 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.

Our Barron facility, which became fully operational in December 2012, currently consists of a sand mine and a wet plant on land that we currently lease and a dry plant on land that we own. This enclosed facility has a rated production capacity of 8,800 tons per day year-round, 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. We utilize 3.1 miles of existing rail track that connects our facility to the rail line owned by Canadian National, making our Barron facility one of only two active Wisconsin-based frac sand mines, and the only one with significant available capacity for future production growth, located on the Canadian National line. Our direct connection to the Canadian National line allows us to offer direct access to the rapidly growing oil and gas shale plays in northwestern Canada and the northeastern United States. In addition, we are currently the only frac sand provider in Wisconsin located on Canadian National's high-capacity rail line designed for rail cars with a 286,000 pound capacity, which will allow us to transport heavier loads and result in reduced transportation costs relative to competitors that only have access to lower capacity infrastructure.

We expect to construct a second wet plant at our Barron facility in order to increase our production capacity. We currently anticipate that this second wet plant will become operational in the first half of 2014 and will have the capacity to process 1.2 million tons of wet sand per year when completed. We have identified property suitable for use as the site of the second wet plant, which we expect will provide us access to the same wide range of high-quality sand that we currently have through our existing Wisconsin facilities.

We believe that the connectivity of our Barron facility to the Canadian National rail line, combined with our existing connection with the Union Pacific line at our New Auburn facility, will provide us enhanced flexibility to accommodate customers located in shale plays throughout North America. We also expect that access to these two rail lines will allow us to provide single line hauls to more shale plays, resulting in faster transit times and a lower delivered cost per ton.

We also mine frac sand at our facility in Kosse, Texas that is processed into a high-quality, 100 mesh frac sand, generally used in dry gas drilling applications. In favorable pricing markets, washed sand is shipped 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. As a result of the quality and diversity of our sand reserves, we have the operational flexibility to alter a portion of our produced sand mix to meet customer needs as the market prices for crude oil and natural gas adjust in the future.

At June 30, 2012, we had approximately 75.1 million tons of proven recoverable sand reserves, as estimated by our third party reserve engineers, and the capacity to produce up to 3.5 million tons and 1.9 million tons of wet sand and dry sand per year, respectively. At June 30, 2012 operations at our New Auburn facility accounted for approximately 24.6 million tons of proven recoverable sand reserves and approximately 2.0 million tons and 1.3 million tons of our annual wet and dry sand production capacity, respectively.

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 and the industry experience of our senior management team have positioned us as a highly attractive source of frac sand to the oil and natural gas industry.

Our Fuel Processing and Distribution 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, and process it into refined products such as conventional gasoline and low sulfur diesel. While a meaningful portion of our transmix business is conducted on a spot basis, we currently purchase approximately 63% of our supply of transmix pursuant to exclusive contracts having a volume-weighted average remaining duration of 17 months as of December 31, 2012. 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 addition to processing transmix and selling refined products, we provide a suite of complementary fuel products and services, including third-party terminaling services, the selling of wholesale petroleum products, certain reclamation services (which consist primarily of tank cleaning services) and blending of renewable fuels.

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

Our frac sand facilities are located in New Auburn, Wisconsin, Barron County, Wisconsin and Kosse, Texas. Based on our own internal estimates we have approximately 75.1 million tons of proven recoverable ISO and API quality sand reserves, including approximately 22.0 million tons of proven recoverable reserves that will supply our Barron facility. We are currently capable of producing up to 4.3 million tons and 5.2 million tons of dry and wet sand per year, respectively, from our current facilities. Upon the completion of a second wet plant to service our Barron facility, which we expect to occur in the first half of 2014, we anticipate having production capacity of 6.4 million wet tons per year. In addition, we believe that up to approximately 80% of the mined frac sand from our Wisconsin operations can be produced in 16/30, 20/40 and 30/50 mesh sizes without any material change to our cost structure. 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 in the United States.

We believe that our strategically located mines and facilities provide us with a large and high-quality mineral reserves base. "Reserves" are defined by SEC Industry Guide 7 as that part of a mineral deposit that could be economically and legally extracted or produced at the time of the reserve determination. Industry Guide 7 divides reserves between "proven (measured) reserves" and "probable (indicated) reserves" which are defined as follows:

We categorize our reserves as proven recoverable in accordance with these SEC definitions and have further limited the definition to apply only to sand reserves that we believe could be extracted at an average cost (excluding inflation and potential commodity price fluctuations) in line with recent historical performance. According to such a definition, we estimate that we had a total of approximately 75.1 million tons of proven recoverable mineral reserves as of June 30, 2012, including the 22.0 million tons of proven recoverable reserves that are supplied from our Barron facility. 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"), Cooper Engineering Company, Inc. ("Cooper Engineering") and Westward Environmental, Inc. ("Westward") have prepared estimates of our proven mineral reserves at our New Auburn, Barron and Kosse facilities, respectively, as of June 30, 2012. Our external geologists and internal engineers update our reserve estimates annually, making necessary adjustments for operations at each location during the year and additions or reductions due to property

acquisitions and dispositions, quality adjustments and mine plan updates. Before acquiring new reserves, we perform surveying, drill core analysis and other tests to confirm the quantity and quality of the acquired reserves.

As of July 2012, we owned approximately 38% of our mineral reserves and leased approximately 62% of our reserves from third-party landowners, which we describe in more detail below. Our New Auburn and Barron leases expire in 2036 and 2037, respectively, and 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, SEH and Westward 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. In rendering its opinion regarding the proven recoverable reserves attributable to our Barron facility, Cooper Engineering determined, based on their knowledge of the Barron mineral reserve and our intended plan of operations, that it is reasonable to assume our Barron operating costs will not exceed those of our New Auburn facility.

The cutoff grade used by SEH in estimating our reserves considers only sand that will not pass through a 70 mesh screen as proven recoverable reserves, meaning that only sands with mesh sizes coarser than 70 are included in SEH's estimate of our proven recoverable reserves. Based on the coarse nature of the mineral deposit and our intended mining plan, Cooper Engineering estimated our reserves using a cutoff grade of 50 mesh, meaning only sands with mesh sizes coarser than 50 are included in the estimate of proven recoverable reserves. 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, meaning that only sands within this range are included in Westward's estimate of our proven recoverable reserves.

The following table provides information regarding our current and planned frac sand production facilities as of December 31, 2012.

Our plant in Kosse, Texas and all of our dry plants operate year-round and are managed by crews of four to six employees who work 12-hour shifts and average 40-hour weeks, which allows us to optimize facility utilization. Our wet plants in Wisconsin are managed by crews of four to six employees who work 40-hour weeks, with shifts between eight and 12 hours depending on the employee's function; however, because raw sand cannot be wet-processed during extremely cold temperatures, frac sand is typically washed only nine months out of the year at our Wisconsin operations. 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.

In response to customer demand for frac sand for use in hydraulic fracturing operations, we began construction of a wet sand plant and dry sand plant facility in New Auburn, Wisconsin in April 2011 and commenced operations less than seven months later, in October 2011. We lease the mineral rights to a 418-acre mine site located adjacent to our New Auburn wet plant that, as of June 30, 2012, contained approximately 24.6 million tons of proven recoverable reserves, of which approximately 100% were coarser than 70 mesh. The mineral reserves at our New Auburn facility are secured under mineral leases that expire in 2036. Pursuant to these lease agreements we make payments totaling $1.37 for royalties and lease development fees for each ton of sand that we produce at our New Auburn wet plant that is convertible into saleable sand. In addition, these agreements require us to mine an aggregate of at least 75,000 tons of sand each year. In the event we mine less than 75,000 tons of sand during a calendar year, the landowners may unanimously elect to terminate all of the leases unless we pay them a $350,000 aggregate cure payment to retain the leases. If we do not mine any raw sand product during a calendar year, we are required to pay $5,000 to each landowner in lieu of mining raw sand product from their property that year. Additionally, we have obtained surface lease rights to 65 acres on the wet plant site that permit us to stockpile processed product and to construct, operate and maintain our wet plant and related pond and water transportation infrastructure. The surface leases expire in 2036.

Our New Auburn wet plant facility is comprised of 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. Our New Auburn dry plant sits inside a metal enclosed building designed to minimize weather-related effects and contains a 175 ton per hour natural gas fired fluid bed dryer as well as five high capacity gyratory mineral separators. The dryer is capable of producing 1.3 million tons per year of dry northern Ottawa white frac sand in varying gradations, including 16/30, 20/40, 30/50 and 40/70 mesh. For the year ended December 31, 2012, our New Auburn facility sold approximately 1,035,650 tons of 16/30, 20/40, 30/50 and 40/70 mesh sand. The coarseness and conductivity of our northern Ottawa white frac sand significantly enhances recovery of oil and liquids-rich gas by allowing hydrocarbons to flow more freely than smaller, finer frac sands. In addition, its crush resistant properties enable northern Ottawa white frac sand to be used in deeper drilling applications than the frac sand produced by many of our peers whose mineral deposits are located in Texas, Arkansas or other southern United States locations. We believe the higher crush strength properties of our northern Ottawa white sand provides us with a significant competitive advantage in supplying frac sand.

The deposits found in our open-pit New Auburn mine are Cambrian quartz sandstone deposits that produce high-quality northern Ottawa white frac sand and have a minimum silica (SiO2) content of 99%. Fred Weber, a third-party contractor that operates our mine at this location, uses 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. Mined sand is then slurrified and pumped to the wet plant for processing.

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 crop land. As of December 31, 2012, excavating activities consisting of mining, overburden removal and reclamation, had taken place on approximately 60 of the 418 acres of our New Auburn property. No underground mines are operated at our New Auburn location as all mining activities take place on the surface and above the water table.

Our New Auburn mine and the wet sand processing facility are located approximately 12 miles south of our dry plant and are strategically located on a county road that provides us with year-round trucking access. 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 Union Pacific 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 Union Pacific short rail line provides our customers with the ability to transport northern Ottawa white frac sand from our New Auburn facility to all major unconventional oil and natural gas basins currently producing in the United States.

In order to keep pace with rapidly increasing demand for our northern Ottawa white frac sand, we have acquired the mineral rights to five adjacent mineral deposits in Barron County, Wisconsin that together account for 262 acres and that contain approximately 22.0 million tons of proven recoverable sand reserves, based on the report of our third-party independent mining engineers. As of December 31, 2012, we have begun extracting sand from our Barron mine but had not yet removed any sand from the property. Our Barron facility currently consists of a wet plant built on our 262-acre lease site with the capacity to process 1.2 million tons per year and a dry plant with the capacity to process 2.4 million tons of dry northern Ottawa white frac sand per year in gradations of 16/30, 20/40, 30/50, 40/70 and 100 mesh. Construction on the dry plant began in June 2012 and construction on the first wet plant began in September 2012, with both plants fully operational in December 2012. We also intend to build a second wet plant which is expected to be completed in the first half of 2014 on property that we believe will provide us access to the same wide range of high-quality sand that we currently have through our New Auburn and Barron facilities. We expect this facility to have the capacity to process 1.2 million tons of wet sand per year when completed, increasing the aggregate amount of wet sand that our Barron facility can process to 2.4 million tons per year, excluding the 500,000 tons of contracted wet sand capacity with Midwest Frac.

The mineral reserves at our Barron facility are secured under mineral leases that expire in 2037. Pursuant to these lease agreements we make payments totaling $1.00 for royalties for each ton of sand that we produce at our Barron wet plant that is convertible into saleable sand. In addition, these agreements require us to mine an aggregate of at least 250,000 tons of sand each year. In the event we mine less than 250,000 tons of sand during a calendar year, we are required to pay the landowners an aggregate $250,000 payment on or before December 31 of the calendar year in which we fail to mine the minimum quantity. Additionally, we have obtained surface lease rights to 35 acres on the wet plant site that permit us to stockpile processed product and to construct, operate and maintain our wet plant and related pond and water transportation infrastructure. The surface lease expires in 2037.

The deposits found in our Barron mine are Cambrian quartz sandstone deposits with a minimum silica (SiO2) content of 99% that produce high-quality northern Ottawa white frac sand with substantially similar attributes to the sand found in our New Auburn mine. Heavy equipment is used to mine unconsolidated 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 crop land. As of December 31, 2012, mining had commenced, but no sand had been removed from our Barron property.

We have incorporated into our Barron facility the same logistical and transportation efficiencies that we employ at our other facilities. Specifically, the wet plants are located within nine miles of the dry plant and accessible by truck year-round. The dry plant is adjacent to a section of the Canadian National rail line that can be used to facilitate the shipment of our products to customer drilling sites throughout the United States and Canada. We have entered into a long-term agreement with Canadian National pursuant to which it invested $35 million to restore nearly 40 miles of track and reestablish rail service along the line that will tie into our Barron facility. We expect to ship the majority of the sand produced at our Barron facility on the Canadian Rail line and have 3.1 miles of on-site rail track to accommodate unit trains. We have room for expansion should we decide to increase our rail infrastructure.

In addition, in order to secure access to additional raw northern Ottawa white frac sand, we have 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. We will be obligated to purchase at least 200,000 tons of wet sand and we will have the right to purchase an annual allotment of up to 500,000 tons of wet sand from Midwest Frac's mine per year. 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. After receiving full payment for our investment in the wet plant, ownership of the wet plant will transfer to Midwest Frac. Midwest Frac's mine is located approximately 9.5 miles from our Barron lease and we believe the coarseness, conductivity and crush-resistant properties of this raw sand will be substantially similar to the properties of the sand we mine from our New Auburn facility. Construction on the wet plant began in June 2012, and operations commenced in September 2012. Although we will initially own the wet plant, Midwest Frac will operate and maintain it throughout the term of the contract. 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. In accordance with the terms of the 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. Total capital we deployed to construct the wet plant on the land owned by Midwest Frac was approximately $2.7 million.

We have also entered into a ten-year dry sand tolling agreement with Midwest Frac pursuant to which we will provide dry sand conversion services for Midwest Frac for a fixed price per ton. The agreement is structured similarly to a take-or-pay arrangement in that if Midwest Frac does not supply a minimum quantity of wet sand to us for conversion under the tolling agreement, then our purchase price per ton of sand under our sand supply agreement with Midwest Frac will be retroactively reduced.

Our Kosse, Texas facility was constructed and commenced operations in 2009. We own the mineral rights to a 225-acre mineral deposit located adjacent to our processing plant. The deposit has a minimum silica content of 99% and controlling attributes that include sand grain crush strength and size distribution. As of June 30, 2012, the Kosse mineral deposit contained approximately 28.5 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. We are not obligated to make any royalty payments in connection with our mining operations at this location. Heavy equipment is used to mine sand from the open-pit. The current mining area of our Kosse property covers approximately 65 acres and no reclamation has been performed.

The wet plant at our Kosse facility is capable of producing up to 1.5 million tons per year of wet sand. The dry plant utilizes a 200 ton per hour natural gas fired rotary dryer that is capable of producing up to 0.6 million tons per year of dry native Texas frac sand. For the year ended December 31, 2012, our Kosse facility produced and sold approximately 146,100 tons of dry native Texas frac sand and high quality frac sand mined in Wisconsin, including 57,900 tons of shortfall volumes related to our take-or-pay contracted volume associated with our frac sand mined in Texas. Currently, all sales from the Kosse facility are picked up by trucks that access the plant from adjoining county roads.

Given its proximity to the Eagle Ford, Haynesville and Barnett shales and the Permian Basin, SSS has demonstrated a historical ability to use excess Kosse capacity to process wet sand shipped in unit trains from Wisconsin into high-margin finished frac sand that can be sold throughout the southwest United States. The Kosse facility has three dedicated on-site 1,000 ton storage silos, which allows us to directly store sand close to drilling activity in the southwestern United States as opposed to our competitors, most of which whom must pay fees to third parties for sand storage and transload providers. The facility provides mid-sized oilfield services companies, who lack the scale to justify dedicated rail fleets, access to coarse northern Ottawa white frac sand and provides a sand source to

customers who cannot secure sufficient storage adjacent to rail offloading facilities. Additionally, our Kosse facility allows for immediate delivery via truck of dried sand to customers who have depleted their inventory and who otherwise would have to hold crews and equipment idle until the next rail shipment of product arrives. We believe that a connection to the Union Pacific mainline could be constructed less than two miles away from our Kosse facility, which would reduce the transportation costs we currently incur in trucking the sand from the existing rail line to our facility.

We also believe there are opportunities to contract with storage terminal operators in south Texas or Pennsylvania to establish an alternative distribution channels for our products. Through such an arrangement, we could ship wet sand directly to the storage terminal operator and use an onsite dryer to convert the wet sand into finished products. Doing so would further allow us to provide our customers with a flexible source of just-in-time inventory while limiting the extensive silo and storage investment relative to traditional storage terminal operators.

While transporting product from our plants to the ultimate hydraulic fracturing site is the responsibility of our customers and their contractors, we provide our customers the ability to ship frac sand products via truck, rail, ship or barge in an effort to help our customers better manage transportation costs. At our Kosse, Texas plant, all order volume is 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 Ottawa 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.

Due to limited storage capacity at most transload points, 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 an effort to further differentiate ourselves as a full service frac sand provider, we have started to offer our customers a total supply chain solution pursuant to which we manage every piece of the supply chain from mining and manufacturing all the way to direct to the well-head delivery. Given the relative weight of transportation and logistics expenditures as a percentage of total delivered frac sand cost, we believe such a service offering will 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, entered into agreements with transload and terminal storage providers 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 freight on board 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.

The Barron facility is currently one of two Wisconsin-based frac sand mines, and the only one with significant available capacity for future production growth, located on the Canadian National line. In addition, we are currently the only frac sand provider in Wisconsin located on Canadian National's high-capacity rail line designed for rail cars with a 286,000 pound capacity, and our access to this rail line will allow us to transport heavier loads and result in reduced transportation costs relative to competitors that only have access to lower capacity infrastructure. Access to the Canadian National line provides us with the ability to ship sand from our Barron facility to all major shale plays throughout the United States and Canada, and it provides us with direct service on the only railroad that serves all of the oil and gas shales in northwestern Canada. We have entered into a long-term agreement with Canadian National pursuant to which it invested $35 million to restore nearly 40 miles of track and reestablish rail service along the line that ties into our Barron facility. We agreed to construct and maintain, at our expense, a rail facility at our Barron facility, which allows for the loading and switching of rail cars. We also agreed to ship a minimum number of tons per year on the Canadian National line at set prices per rail car and by destination. We expect to ship a majority of the sand produced at our Barron facility on the Canadian National line and have 3.1 miles of on-site rail track to accommodate full unit trains. We expect to be able to load approximately 80 rail cars per day for a total daily loading capacity of 8,800 tons.

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 the permits required for the operation of our Kosse, Texas, New Auburn, Wisconsin and Barron County, Wisconsin facilities.

Permits obtained for our Kosse, Texas facility include (i) construction permits and permits granting access to county or municipal roads, (ii) a Stormwater Pollution Prevention Plan Permit approved by the Texas Commission on Environmental Quality, which regulates water discharge and storm water runoff, and (iii) an Air Quality Standard Permit approved by the Texas Commission on Environmental Quality, which regulates particulate matter emissions and dry plant operation.

Our New Auburn facility currently operates under a construction air permit from the Wisconsin Department of Natural Resources. We must demonstrate our compliance with the construction air permit over an 18-month period, which began in September 2011, after which the Wisconsin Department of Natural Resources will issue an operation air permit. We also developed and comply with a Fugitive Dust Control Plan, a Malfunction Prevention and Abatement Plan and a PM10 monitoring plan. Stormwater discharges from the New Auburn facility are permitted under the Wisconsin Pollutant Discharge Elimination System, or WPDES. An updated Notice of Intent for the WPDES general permit, which will include the new mine areas, is in progress. Placement of all permanent erosion control structures at the New Auburn facility is now complete. We conduct mining operations at the New Auburn facility pursuant to a Chippewa County Nonmetallic Mining Reclamation Permit. We have submitted an updated Nonmetallic Mining Reclamation Plan to Chippewa County and have applied for an amendment to the existing permit to address our proposed mine extension.

Our Barron facility currently operates under a construction air permit from the Wisconsin Department of Natural Resources. We must demonstrate our compliance with the construction air permit over an 18-month period, which began in December 2012, after which the Wisconsin Department of Natural Resources will issue an operation air permit. We are in the process of developing and will comply with a Fugitive Dust Control Plan, a Malfunction Prevention and Abatement Plan and a PM10 monitoring plan. Stormwater discharges from the Barron facility are permitted under the Wisconsin Pollutant Discharge Elimination System, or WPDES. An updated Notice of Intent for the WPDES general permit, which will include the new mine areas, is in progress. Placement of all permanent erosion control structures at the Barron facility is now complete. We conduct mining operations at the Barron facility pursuant to a Barron County Nonmetallic Mining Reclamation Permit.

Our Fuel Processing and Distribution segment consists of our operations in the Dallas-Fort Worth metropolitan area and Birmingham, Alabama. At each location, we acquire transmix from various suppliers and process it into refined products such as conventional gasoline and low sulfur diesel. In order to offer our customers a greater volume and variety of fuel products, we also engage in wholesale fuel distribution and purchase bulk quantities of ultra-low sulfur diesel and reformulated gasoline. In addition, we provide our customers with a suite of complementary fuel products and services, including third-party terminaling, renewable fuel blending and certain reclamation services. The operations at our facilities in the Dallas-Fort Worth metropolitan area, which we refer to as our Dallas-Fort Worth facility, and Birmingham, Alabama, which we refer to as our Birmingham facility, are conducted through our subsidiaries Direct Fuels and AEC, respectively. In these areas, we are able to offer our customers gasoline and diesel at market rates, 24 hours a day, seven days a week.

The following table provides information regarding our Fuel Processing and Distribution assets as of and for the year ended December 31, 2012.

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. For example, in September 2011, we entered into a one-year contract to process a significant quantity of additional transmix per month sourced from the Houston market. 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.

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 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 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 quarter 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 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 approximately 6,186 barrels per day of refined products processed from transmix during the year ended December 31, 2012.

We purchase approximately 25,000 barrels of ultra-low sulfur diesel every 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.

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 approximately 52 trucks per day. The truck rack at our Dallas-Fort Worth facility is fully automated so that drivers can select the specific blend of fuel that meets their needs.

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 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 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. We sold an average of approximately 1,468 barrels per day of refined products processed from transmix at this facility during the year ended December 31, 2012.

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 125 trucks per day. In addition to gasoline and diesel, we also offer our customers biodiesel, ethanol and other additive blending at the rack. The terminals and truck rack at our Birmingham facility is fully automated so that drivers can 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.

We recently recommissioned a biodiesel refinery at our Birmingham facility and began commercial sales in December 2012. Biodiesel contains no petroleum products and can be blended with petroleum 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 either blend biodiesel with a portion of their ultra-low sulfur diesel or purchase and retire a comparable volume of Renewable Identification Numbers (RINS). It is generally more economical to purchase and blend biodiesel than to purchase and retire RINS. This refinery is capable of producing 10.0 million gallons of biodiesel fuel annually.

We also operate reclamation processing 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, or PCW. By reclaiming fuels from these wastes and placing them back into fuel service, our reclamation services eliminate the need for hazardous waste disposal. We also have 18 petroleum tank trailers and 13 vacuum trucks, which enable us to assist in tank cleanings and PCW transportation that range in size and scope.

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 2012.

We currently sell our products primarily under long-term, take-or-pay supply agreements with two of our customers in the oil and gas proppants market. One of the agreements expires in 2021, but either we or our customer may terminate the agreement 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. In addition, we entered into an amendment to this contract that provides the customer the right to purchase up to an additional 50% of the minimum contracted volume of sand from our Barron County facility. Our other primary sales contract has a three-year term and contains customary termination rights for non-performance and expires in 2014. We anticipate extending the term of this agreement or, alternatively, replacing those sales volumes by entering into agreements with new customers. Collectively, sales to customers with long-term sales agreements in 2012 accounted for approximately 89% of our total Sand segment sales volumes, with the remainder consisting of sales on the spot market.

The core customers for our Wisconsin facilities are major oilfield services companies engaged in hydraulic fracturing. Our New Auburn facility's two largest customers, Schlumberger and Baker Hughes, together represented approximately 83% of this facility's processed sand volumes in the year ended December 31, 2012. These customers have signed multi-year take-or-pay contracts that include provisions requiring the customer to pay us an amount designed to compensate us, in part, for our lost margins for the applicable contract year in the event the customer does not take delivery of the minimum annual volume of frac sand specified in the contract. Any sales of the shortfall volumes to other customers on the spot market would provide us with additional margin on these volumes.

As of December 31, 2012, we had take-or-pay contracts in place for 58% of our 1.3 million tons of annual production capacity at our New Auburn facility. As of December 31, 2012, the product mix-weighted average price of sand sold from our New Auburn facility pursuant to these take-or-pay contracts was $53 per ton and the weighted average remaining duration was approximately 4.9 years, assuming that one of our customers does not exercise its early termination right, which will not occur until October 2014 or later, as described elsewhere in this prospectus. If that customer were to exercise its termination right as soon as it became available, the resulting weighted average duration of our take-or-pay contracts to purchase sand from our New Auburn facility would be approximately 1.5 years as of December 31, 2012. As of December 31, 2012, we had take-or-pay or fixed-volume contracts in place for 9% of our 2.4 million tons of annual production capacity at our Barron facility, efforts-based contractual volume accounts for 8% and tolling agreements account for another 10%. As of December 31, 2012, the product mix-weighted average price of sand sold from our Barron facility pursuant to these contracts was $55 per ton and the weighted average remaining duration of these contracts was approximately 5.6 years, or 2.2 years if the termination provision described above is exercised as soon as it becomes available. These averages do not include any volumes under our ten year tolling agreement with Midwest Frac. Should market trends continue to develop as we expect, 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.

As a result of recent expansions in the supply of frac sand and processing capacity and the expectation of continued expansions, we believe that frac sand customers may be increasingly reluctant to enter into take-or-pay contracts that expose the customer to pre-determined financial liability for failure to take delivery of minimum volumes of frac sand. Customers may increasingly pursue fixed-volume contracts, or, alternatively, efforts-based contracts which do not commit the customer to take delivery of specified volumes of frac sand. 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.

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 jobbers 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.

The following table sets forth the revenues attributable to customers that represented more than 10% of the combined revenues for the period indicated:

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 also 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 have awarded Fred Weber, a long-term 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 built the wet plant at our New Auburn facility and now mines the sand reserves, creates stockpiles of washed sand and maintains the plant and equipment at New Auburn. We have 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 term of the agreement or following a default under the contract by 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 Weber to us at the expiration of the term. We mine our own frac sand reserves at our Kosse facility, and have engaged a mining expert to manage excavation activities at our Barron County facility.

We recently entered into a ten-year wet sand supply contract with Midwest Frac pursuant to which we will be 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 County facility, which will initially represent approximately 30% of our wet sand capacity at our Barron County facility. Following completion of our second wet plant facility, which we expect will occur in the first half of 2014, our contracted supply volumes will represent approximately 17% of our total wet sand capacity.

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, generally higher cost of acquisition, 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 63% of our supply of transmix pursuant to exclusive contracts with terms ranging from 12 to 36 months, with a volume-weighted average remaining duration of 17 months as of December 31, 2012. We purchase approximately 14% 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, 2012, our two largest suppliers of transmix accounted for approximately 41% and 8% of our total transmix purchases. The contract with our largest supplier for the year ended December 31, 2012 expires in September 2014 and purchases from our second largest supplier are made pursuant to a month-to-month contract.

We receive transmix by truck or by 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.

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, which has increased in recent years due to favorable pricing and demand trends and which we expect to continue to increase if those trends continue, 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.

Based on management's internal estimates, we believe the five leading producers of frac sand in 2012 were Unimin Corporation, Fairmount Minerals, Ltd., U.S. Silica Holdings, Inc., Preferred Sands, LLC and SSS. Excluding SSS, we believe this group represented in excess of 55% of total industry production in 2012. In addition, in recent years there has 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. As a result of 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 provide us with a competitive advantage relative to new competitors or those seeking to expand their operations in the near term.

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 that, because of their more diverse operations and stronger capitalization, 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.

Fuel terminal customers make their purchasing decisions based on several criteria. The most important 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 trucking. 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.

Because raw sand cannot be wet-processed during sub-zero temperatures, frac sand is typically washed only nine 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 which continues to operate during the winter months, causing the average inventory balance to fluctuate 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-producing basins where severe 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 Adjusted EBITDA 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. For a discussion of the impact of weather on our Sand operations, please read "Risk Factors—Our cash flows fluctuate on a seasonal basis and severe weather conditions could have a material adverse effect on our business" beginning on page 36. Our Fuel Processing and Distribution operations have not historically reflected any material seasonality.

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

We are subject to stringent and complex federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of worker health, safety and the environment. 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 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 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.

The CAA also requires states to draft State Implementation Plans, or SIPs, designed to attain national health-based ambient air quality standards, or 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 recently adopted by the Texas Commission on Environmental Quality, or 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. 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 April 17, 2012, the EPA issued 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 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 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. The rules also establish new emission requirements for compressors, controllers, dehydrators, storage tanks, natural gas processing and certain other equipment, which take effect in 2012. 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 impact our business.

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

Climate change. 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 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.

Water discharge. The Clean Water Act, as amended, or 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.

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 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 United States Department of Energy and the DOI, are evaluating various other aspects of hydraulic fracturing, with the DOI announcing 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. 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, or 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, or CERCLA, and comparable state laws impose strict, joint and several liability without regard to fault or the legality of the original conduct on certain classes of persons that contributed to the release of a hazardous substance into the environment. These persons include the owner and operator of a disposal site where a hazardous substance release occurred and any company that transported, disposed of, or arranged for the transport or disposal of hazardous substances released at the site. Under CERCLA, such persons may be liable for the costs of remediating the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. In addition, where contamination may be present, it is not uncommon for the neighboring landowners and other third parties to file claims for personal injury, property damage and recovery of response costs. We have not received notification that we may be potentially responsible for cleanup costs under CERCLA at any site.

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, or 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, or 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.

Environmental-Related litigation. In April 2006, the owner of land adjacent to the property on which AEC's Birmingham facility is located filed a tort action in Alabama state court against several defendants, including AEC, alleging that toxic contaminants released from the property resulted in the diminution of use and value of the plaintiff's property. The plaintiff sought compensatory and punitive damages, remediation of its property and attorneys' fees. In December 2012, all claims in this litigation were settled by the parties pursuant to a settlement agreement and dismissed with prejudice. In accordance with the settlement agreement, AEC paid the plaintiff $0.8 million as consideration for the release of all claims.

Mining and Workplace Safety. Our sand mining operations are subject to mining safety regulation. The United States Mine Safety and Health Administration, or MSHA is the primary regulatory organization governing the frac sand industry. Accordingly, MSHA regulates quarries, surface mines, underground mines and the industrial mineral processing facilities associated with quarries and mines. The mission of MSHA is to administer the provisions of the Federal Mine Safety and Health Act of 1977 and to enforce compliance with mandatory worker safety and health standards. MSHA works closely with the Industrial Minerals Association, a trade association in which we have a significant leadership role, in pursuing this mission. As part of MSHA's oversight, representatives perform at least two unannounced inspections annually for each above-ground 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 United States Occupational Safety and Health Act, or 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.

We will be managed and operated by the officers and directors of Emerge GP, our general partner. Immediately after the closing of this offering, we expect to employ people either directly or through our general partner. None of our employees are subject to collective bargaining agreements. We consider our employee relations to be good.

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

Our general partner, Emerge GP, will manage our operations and activities. Our general partner is not elected by our unitholders and will not be subject to re-election on a regular basis in the future. As described in the Amended and Restated Limited Liability Company Agreement of Emerge GP (the "GP Agreement"), Emerge GP will be member-managed. Insight Equity, as the controlling member, has delegated to the board of directors all power and authority related to management of the partnership to the fullest extent permitted by law and the GP Agreement. The GP Agreement provides that there shall be three initial directors, who will oversee our operations. The board of directors will elect one or more officers who will serve at the pleasure of the board. Unitholders will not be entitled to elect the directors of Emerge GP or directly or indirectly participate in our management or operation.

Upon the closing of this offering, the board of directors of our general partner will be comprised of seven members, all of whom will be designated by Insight Equity and three of whom will be independent as defined under the independence standards established by the NYSE. The NYSE does not require a listed limited partnership like us 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.

As set forth in the GP Agreement, Emerge GP may, from time to time, have a conflicts committee to which the board of directors will appoint independent directors and which may be asked to review specific matters that the board believes may involve conflicts of interest between us, our limited partners and Insight Equity. The conflicts committee will determine the resolution of the conflict of interest in any manner referred to it in good faith. The members of the conflicts committee may not be officers or employees of our general partner or directors, officers or employees of its affiliates, including Insight Equity, may not hold an ownership interest in the general partner or its affiliates other than common units or awards under any long-term incentive plan, equity compensation plan or similar plan implemented by the general partner or the partnership, and must meet the independence and experience standards established by the NYSE and the Exchange Act to serve on an audit committee of a board of directors, and certain other requirements. Any matters approved by the conflicts committee in good faith will be conclusively deemed to be "fair and reasonable" to us, approved by all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders. Any unitholder challenging any matter approved by the conflicts committee will have the burden of proving that the members of the conflicts committee did not subjectively believe that the matter was in the best interests of our partnership. Moreover, any acts taken or omitted to be taken in reliance upon the advice or opinions of experts such as legal counsel, accountants, appraisers, management consultants and investment bankers, where our general partner (or any members of the board of directors of our general partner including any member of the conflicts committee) reasonably believes the advice or opinion to be within such person's professional or expert competence, shall be conclusively presumed to have been done or omitted in good faith. For a detailed discussion of the potential conflicts of interest we face and how they will be resolved, see "Conflicts of Interest and Duties—Conflicts of Interest" beginning on page 180.

In addition, Emerge GP will have an audit committee comprised of directors who meet the independence and experience standards established by the NYSE and the Exchange Act. The audit committee will assist the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and corporate policies and controls. The audit committee will have the sole authority to retain and terminate our independent registered public accounting firm, approve all auditing services and related fees and the terms thereof, and pre-approve any non-audit services to be rendered by our independent registered public accounting firm. The audit committee will also be responsible for confirming the independence and objectivity of our independent

registered public accounting firm. Our independent registered public accounting firm will be given unrestricted access to the audit committee.

Any person who is or was a member, partner, director, officer, affiliate, fiduciary or trustee of Emerge GP, any person who is or was serving at the request of Emerge GP or any affiliate of Emerge GP as an officer, director, member, manager, partner, fiduciary or trustee of another person is entitled to indemnification under the GP Agreement for actions associated with such roles to the fullest extent permitted by law and the GP Agreement. The GP Agreement may be amended or restated at any time by Insight Equity.

The directors of our general partner hold office until the earlier of their death, resignation, removal or disqualification or until their successors have been elected and qualified. Officers serve at the discretion of the board of directors. There are no family relationships among any of the directors or executive officers of our general partner. The following table shows information regarding the current directors and executive officers of Emerge GP.

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. He intends to devote as much time as is necessary to discharge his duties as a director of Emerge GP and to oversee the management and operations of Emerge Energy Services LP. 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 Boston and Dallas) was from September 1985 to December 1999. While at Bain, Mr. Beneski advised Fortune 100 clients across a wide range of industries in the areas of portfolio and business unit strategy, mergers and acquisitions, operational improvement, organizational and process redesign, new product introduction and growth strategy. Prior to 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 was elected Chief Executive Officer of our general partner in April 2012 and expects to devote substantially all of his professional time to Emerge Energy Services LP. Since May 2010, Mr. Shearer has served as President and Chief Executive Officer of SSS. He will continue to directly manage the operations of the Sand Segment following the offering. 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 was elected Vice President and appointed as a member of the board of directors of our general partner in April 2012 and expects to devote approximately 40% of his professional time to Emerge Energy Services LP, where he will directly manage the operations of the Fuel Processing and Distribution Segment following the offering. 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 due to his affiliation with Insight Equity, his knowledge of the industries in which we operate and his financial and business expertise.

Robert Lane was appointed Chief Financial Officer of our general partner in November 2012 and expects to devote all of his professional time to Emerge Energy Services LP following the offering. 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 Certified 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 has served as a member of our board of directors since March 2013. He intends to devote as much time as is necessary to discharge his duties as a director of Emerge GP and to oversee the management and operations of Emerge Energy Services LP. 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 was appointed as an independent director of our general partner in March 2013. He intends to devote as much time as is necessary to discharge his duties as a director of Emerge GP and to oversee the management and operations of Emerge Energy Services LP. Mr. Kelly is the Vice Chairman of 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. 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 thirty-five year career in the field of branding, advertising, and integrated marketing communications also includes time at Young & Rubicam New York.

Mr. Kelly received his MBA from Harvard Business School and his Bachelor of Arts degree from Amherst College. He 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 was appointed as an independent director of our general partner in July 2012. He intends to devote as much time as is necessary to discharge his duties as a director of Emerge GP and to oversee the management and operations of Emerge Energy Services LP. 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. was appointed as a member of the board of directors of our general partner in March 2013. He intends to devote as much time as is necessary to discharge his duties as a director of Emerge GP and to oversee the management and operations of Emerge Energy Services LP. 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 was appointed as a member of the board of directors of our general partner in April 2012. He intends to devote as much time as is necessary to discharge his duties as a director of Emerge GP and to oversee the management and operations of Emerge Energy Services LP. 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 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 where he was responsible for company due diligence and transaction execution, as well as working overseas in the Middle East advising the Saudi government on business investments from 1991 to 1992.

Mr. Vescovo also serves as a Managing Director and board member of all of Insight Equity's portfolio companies, including AEC Holdings and SSH. Additionally, Mr. Vescovo is a Commander (0-5) in the US Navy Reserve with a specialization in operational targeting. 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 BA 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.

Our general partner will not receive any management fee or other compensation for its management of us. Our general partner and its affiliates will be reimbursed for all expenses incurred on our behalf, including the compensation of employees of Emerge GP or its affiliates that perform services on our behalf. These expenses include all expenses necessary or appropriate to the conduct of our business and that are allocable to us. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. There is no cap on the amount that may be paid or reimbursed to our general partner or its affiliates for compensation or expenses incurred on our behalf.

This section describes the material components of the executive compensation program for our executive officers who are named in the "2012 Summary Compensation Table" below. Our named executive officers and their positions for the year ended December 31, 2012 consisted of the following two individuals:

We expect that, following the completion of this offering, Mr. Shearer will serve as our President and Chief Executive Officer and Mr. Bonham will serve as our President, Fuel Division.

The following table sets forth certain information with respect to the compensation paid to the named executive officers for the year ended December 31, 2012.

SSS and Mr. Shearer are parties to an employment letter, dated March 23, 2010 and amended May 17, 2011, that provides for Mr. Shearer's employment as Chief Executive Officer of SSS. Under his amended employment letter, Mr. Shearer's annual base salary was $230,000, which, beginning in May 2011, is subject to automatic increases by four percent on each May 1 while he remains employed at SSS. The amended employment letter also provides that Mr. Shearer is eligible to participate in a long-term incentive compensation program, as described in further detail below, as well as the welfare benefit plans maintained by SSS on the same basis as other employees of that company.

In October 2012, we entered into an employment letter with Robert Lane pursuant to which Mr. Lane currently serves as Chief Financial Officer of Emerge GP. Under his employment 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, Mr. Lane is entitled to receive 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 the company from time to time.

Mr. Shearer's amended employment letter and Mr. Lane's employment letter also provide for certain payments and benefits upon a termination of employment by the company without "cause" (as defined in the applicable employment letter), as described under "—Severance and Change in Control Benefits" below.

We have not entered into an employment letter or employment agreement with Mr. Bonham.

The named executive officers receive a base salary to compensate them for services rendered to the respective 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.

In February 2012, Mr. Bonham's annual base salary was reduced to $134,000. The following table provides the annual base salary rate for each of the named executive officers as of December 31, 2012.

We expect that, following the completion of this offering, base salaries for the named executive officers will be reviewed periodically by the board of directors of our general partner or the compensation committee, with adjustments expected to be made generally in accordance with the considerations described above and to maintain base salaries at competitive levels.

In 2012, each of the named executive officers participated in an annual incentive bonus compensation program under which cash bonuses were awarded.

For 2012, Mr. Shearer was eligible to receive an annual incentive bonus at the discretion of the board of directors of SSS. Based on the strong financial performance of SSS in 2012, the board awarded him a cash bonus of $200,000.

For 2012, Mr. Bonham was eligible to receive an annual incentive bonus based on the achievement by Direct Fuels of pre-established EBITDA targets. Achievement of EBITDA, at the threshold level would result in a bonus payment equal to 40% of Mr. Bonham's annual base salary, and achievement beyond the threshold level would result in an increased bonus payout percentage, determined by straight-line interpolation. Based on the 2012 adjusted EBITDA achieved by Direct Fuels, Mr. Bonham was awarded a cash bonus equal to 78% of his 2012 base salary, or $116,436.

The actual annual cash bonuses awarded to Messrs. Shearer and Bonham for 2012 performance are set forth above in the 2012 Summary Compensation Table.

For 2012, Mr. Lane was eligible to receive an incentive bonus with a target payout of 50% of his salary prorated for the portion of the year he was employed by us. The actual bonus awarded is at the discretion of our general partner. We have not yet paid Mr. Lane a bonus with respect to 2012 services but expect to pay any such bonus in 2013.

Mr. Shearer currently participates in a long-term incentive compensation program maintained by SSS, referred to as the LTIC, pursuant to which Mr. Shearer is 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 LTIC, in the event of an ultimate sale transaction, Mr. Shearer is eligible to receive up to 5.30% of the net cash proceeds received in such transaction in excess of $25,000,000. Mr. Shearer will vest as to 50% of his right to receive any such payment on each of May 1, 2012 and May 1, 2013 or, if earlier, as to 100% of his right to receive any such payment upon the consummation of an ultimate sale transaction, subject to his continued employment through the applicable vesting date(s). Any amounts to which Mr. Shearer may become entitled under the LTIC will be paid in a lump sum within 90 days following the closing of the ultimate sale transaction. We expect that we and Mr. Shearer will terminate the LTIC in connection with the consummation of this offering.

Mr. Lane's employment letter provides that he is eligible to participate in two long-term incentive compensation programs. Under the first program (the "MQD LTIC"), Mr. Lane is eligible to receive a cash bonus of up to $100,000 for each of 2013, 2014 and 2015 based on the amounts by which the company's distributions to its investors exceeds the forecasted quarterly distribution levels established in

connection with this offering. 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 based on the amount by which the average daily trading value of the company's common units for the applicable year exceeds the per unit equity value of our common units upon the completion of this offering. Each of the MQD LTIC and the Unit Price LTIC will be calculated on an annual basis and will be 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.

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

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 company-paid annual physical exams, which are supplemental to the health benefits provided to employees of SSS generally. SSS has also agreed to pay Mr. Shearer an automobile allowance equal to $400 per month.

SSS and Direct Fuels maintain 401(k) retirement savings plans for their employees, including Mr. Shearer and Mr. Bonham, who satisfy certain eligibility requirements. In 2012, Mr. Lane did not participate in a 401(k) plan. 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. Currently, SSS and Direct Fuels match contributions made by participants in the 401(k) plan up to a specified percentage of the employee contributions, and these matching contributions are fully vested as of the date on which the contribution is made. 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. We do not expect these perquisites to be a material component of our compensation program.

None of the named executive officers held any equity awards that were outstanding as of December 31, 2012.

In connection with the consummation of this offering, we expect that our general partner will grant equity-based awards to certain key employees, including some or all of our named executive officers,

under a long-term incentive plan that we intend to adopt in connection with this offering. The terms of such awards and the amounts to be granted to each award recipient have not yet been determined.

Mr. Shearer's amended employment letter provides that if Mr. Shearer's employment is terminated by SSS without "cause" (as defined in the amended employment 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 his then-current annual base salary, payable over a period of twelve months or as a lump sum, as determined in the discretion of SSS.

Mr. Lane's employment letter provides that if his employment is terminated by the Company without "cause" (as defined in the employment 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 employment letter), 1.5 times his annual base salary) and (b) immediate vesting in, and payment of, the MQD 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.

Prior to the consummation of this offering, our general partner intends to adopt a 2013 Long-Term Incentive Plan, or LTIP, pursuant to which eligible individuals may receive awards with respect to our equity interests, thereby linking the recipients' compensation directly to our performance. The description of the LTIP set forth below is a summary of the anticipated material features of the LTIP. This summary, however, does not purport to be a complete description of all of the anticipated provisions of the LTIP. In addition, our general partner is still in the process of implementing the LTIP and, accordingly, this summary is subject to change prior to the effectiveness of the registration statement of which this prospectus is a part.

The LTIP will provide for the grant of unit awards, restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights and other unit-based awards. Subject to adjustment in the event of certain transactions or changes in capitalization, it is expected that an aggregate of common units may be delivered pursuant to awards under the LTIP. Awards that are forfeited, cancelled, exercised paid or otherwise terminates or expires without the actual delivery of units will be available for delivery pursuant to other awards. Units that are withheld to satisfy tax withholding obligations or payment of an award's exercise price will not be available for future awards. We expect that the LTIP will be administered by the board of directors of our general partner, which we refer to as the plan administrator. The LTIP will be designed to promote our interests, as well as the interests of our unitholders, by rewarding the officers, employees and directors of our general partner for delivering desired performance results, as well as by strengthening our general partner's ability to attract, retain and motivate qualified individuals to serve as directors, consultants and employees.

Our employees, consultants and directors, and employees, consultants and directors of our general partner and our respective affiliates will be eligible to receive awards under the LTIP.

The plan administrator will be able to grant unit awards to eligible individuals under the LTIP. A unit award is an award of common units that are fully vested upon grant and are not subject to forfeiture.

A restricted unit is a common unit that is subject to forfeiture. Upon vesting, the forfeiture restrictions lapse and the recipient holds a common unit that is not subject to forfeiture. A phantom unit is a notional unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit or on a deferred basis upon specified future dates or events or, in the discretion of the plan administrator, cash equal to the fair market value of a common unit. The plan administrator will be able to make grants of restricted and phantom units under the LTIP that contain such terms, consistent with the LTIP, as the plan administrator may determine are appropriate, including the period over which restricted or phantom units will vest. The plan administrator will, in its discretion, be able to base vesting on the grantee's completion of a period of service or upon the achievement of specified financial objectives or other criteria or upon a change of control (as defined in the LTIP) or as otherwise described in an award agreement.

We expect that distributions made by us with respect to awards of restricted units will, in the discretion of the plan administrator, be subject to the same vesting requirements as the restricted units. The plan administrator, in its discretion, will also be able to grant tandem distribution equivalent rights with respect to phantom units. Distribution equivalent rights 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.

We expect that the LTIP will also permit the grant of options covering common units and unit appreciation rights. Unit options represent the right to purchase a number of common units at a specified exercise price. Unit appreciation rights represent the right to receive the appreciation in the value of a number of common units over a specified exercise price, either in cash or in common units as determined by the plan administrator.

We expect that the LTIP will permit unit options and unit appreciation rights to be granted to such eligible individuals and with such terms as the plan administrator may determine, consistent with the LTIP; however, a unit option or unit appreciation right must have an exercise price equal to at least the fair market value of a common unit on the date of grant. We expect that the term of each unit option and unit appreciation right will be no more than ten years from the applicable grant date.

The LTIP will also permit the grant of "other unit-based awards," which are awards that, in whole or in part, are valued or based on or related to the value of a unit. The vesting of another unit-based award may be based on a participant's continued service, the achievement of performance criteria or other measures. On vesting or on a deferred basis upon specified future dates or events, another unit-based award may be paid in cash and/or in units (including restricted units), as the plan administrator may determine.

Common units to be delivered with respect to awards may be newly-issued units, common units acquired in the open market, common units acquired directly from our affiliates or any other person or any combination of the foregoing. We expect that all awards will be subject to the provisions of any

claw-back policy implemented by the plan administrator, to the extent set forth in such claw-back policy and/or required by applicable law or applicable securities exchange listing standards.

The plan administrator will have broad discretion to take action under the LTIP, as well as make adjustments to the terms and conditions of existing and future awards, to prevent the dilution or enlargement of intended benefits and facilitate necessary or desirable changes in the event of certain transactions and events affecting our common units, such as unit distributions, unit splits, mergers, acquisitions, consolidations and other corporate transactions. In addition, in the event of certain non-reciprocal transactions with our equity holders known as "equity restructurings," we expect that the plan administrator will make equitable adjustments to the LTIP and outstanding awards. In the event of a change in control of our company (as defined in the LTIP), to the extent that the surviving entity declines to continue, convert, assume or replace outstanding awards, then all such awards will become fully vested and exercisable in connection with the transaction. Individual award agreements may provide for additional accelerated vesting and payment provisions.

The plan administrator, at its discretion, will be able to terminate the LTIP at any time with respect to the common units for which a grant has not previously been made. The LTIP will automatically terminate on the 10th anniversary of the date it was initially adopted by our general partner. The plan administrator will also have the right to alter or amend the LTIP or any part of it from time to time or to amend any outstanding award made under the LTIP, provided that no change in any outstanding award may be made that would materially impair the vested rights of the participant without the consent of the affected participant; however, except in connection with certain changes in our capital structure, unitholder approval will be required for any amendment that (i) as required by applicable law or the rules of the applicable securities exchange (including without limitation an increase to the number of units available under the LTIP), (ii) "reprices" any unit option or unit appreciation right by reducing its per unit exercise price, or (iii) cancels any unit option or unit appreciation right in exchange for cash or another award when the unit option or unit appreciation right price per unit exceeds the fair market value of the underlying units.

In 2012, none of our non-employee directors received cash or equity compensation for their services as a director. In connection with this offering, we intend to approve and implement a compensation program for our non-employee directors, whom we refer to as eligible directors, that consists of a combination of cash annual retainer fees and long-term equity-based compensation, as described below:

Under the program, each eligible director will be entitled to receive an annual cash retainer of $50,000. In addition, each committee chairperson will receive a $10,000 annual cash retainer and each non-chair committee member will receive a $2,500 annual cash retainer. We currently expect to establish an audit committee.

Under the program, an eligible director who joins the board of directors after the completion of this offering will receive a grant of restricted units covering a number of units having a value equal to $60,000 when he or she joins our board of directors, pro-rated to reflect any partial year service. Each restricted unit grant will vest in full on the first anniversary of the initial election of appointment of the eligible director, subject to the eligible director's continued service with our company through the

applicable vesting date. In addition, an eligible director will receive an annual restricted unit grant valued at $60,000 on , which will vest in full on , subject to continued service through the applicable vesting date.

The following table sets forth the beneficial ownership of our units that will be issued upon the consummation of this offering and the related transactions and held by:

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 , 2013, 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 and their address is 1400 Civic Place, Suite 250, Southlake, Texas 76092.

At the closing of this offering, our general partner and its affiliates will own common units representing an aggregate % limited partner interest in us (or common units representing an aggregate % limited partner interest in us, if the underwriters exercise their option to purchase additional common units in full).

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


Pre-IPO Stage
The consideration received by our general partner and its affiliates prior to or in connection with this offering		common units; and
		a non-economic general partner interest.
Operational Stage
Distributions of available cash to Insight Equity and its affiliates		We will generally make cash distributions to the unitholders pro rata. Immediately following this offering, based on ownership of our common units at such time, Insight Equity and its affiliates will own approximately % of our common units ( % if the underwriters exercise their over-allotment option in full) and would receive a pro rata percentage of the available cash that we distribute in respect thereof.
Reimbursements to our general partner and its affiliates		We will reimburse our general partner and its affiliates, including Insight Equity, for the following payments of direct and indirect expenses incurred on our behalf, subject to certain limitations:
		• ; and
		• .
Withdrawal or removal of our general partner		If our general partner withdraws or is removed, its general partner interest will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests. Please read "The Partnership Agreement—Withdrawal or Removal of our General Partner" beginning on page 198.
Liquidation Stage
Liquidation		Upon our liquidation, the partners, including the general partner, will be entitled to receive liquidating distributions according to their respective capital account balances.

We and other parties have entered into or will enter into the various documents and agreements that will effect the transactions relating to our formation and this offering. These agreements will not be the result of arm's-length negotiations, and they, or any of the transactions that they provide for, may not be effected on terms as favorable to the parties to these agreements as could have been obtained from unaffiliated third parties. All of the transaction expenses incurred in connection with these transactions will be paid from the proceeds of this offering.

We and other parties have entered into other agreements with certain of our affiliates, as described in more detail below. These agreements will affect the offering transactions, including the vesting of assets in, and the assumptions of liabilities by, us and our subsidiaries, and the application of the proceeds of this offering. These agreements have been negotiated among affiliated parties and, consequently, are not the result of arm's-length negotiations.

Our subsidiaries regularly receive general and administrative services from employees of Insight Equity and reimburse Insight Equity for the fees and expenses it incurs in conjunction with the provision of those services. Our subsidiaries collectively reimbursed Insight Equity $0.5 million for such services in 2012.

We expect to enter into an administrative services agreement with Insight Management Company LLC pursuant to which Insight Management Company LLC will provide specified general and administrative services to us and our subsidiaries from time to time. Under the anticipated terms of the agreement, we would 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 will be an employee of Insight Management Company LLC and will serve as the head of our Fuel Processing and Distribution segment, and we will reimburse Insight Management Company LLC for an allocation of Mr. Bonham's time and expenses incurred in providing services to us. We expect that the 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 expect that the terms of the administrative services agreement will be no less favorable to us than those generally available from unrelated third parties.

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. We expect LBC Credit Partners, L.P. will indirectly own % of our general partner and of our common units upon the closing of this 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 4% 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 will

bear cash interest at a rate of 12% per annum and PIK interest at a rate of 6% per annum. We also expect to repay the second lien term loan in full at the closing of this offering.

An affiliate of Insight Equity has 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 SSH. We expect that this letter of credit will be retired at the closing of this offering.

Affiliates of Insight Equity and LBC Credit Partners, L.P. have 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, 2012, the outstanding balance under these letters of credit was $6.7 million. 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

The board of directors of our general partner will adopt a code of business conduct and ethics in connection with the closing of this offering that will provide that the board of directors of our general partner or its authorized committee will 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 will provide that our management will make all reasonable efforts to cancel or annul the transaction.

The code of business conduct and ethics will provide that, in determining whether or not to recommend the initial approval or ratification of a related person transaction, the board of directors of our general partner or its authorized committee should consider all of the relevant facts and circumstances available, including (if applicable) but not limited to: (i) whether there is an appropriate business justification for the transaction; (ii) the benefits that accrue to us as a result of the transaction; (iii) the terms available to unrelated third parties entering into similar transactions; (iv) the impact of the transaction on a director's independence (in the event the related person is a director, an immediate family member of a director or an entity in which a director or an immediately family member of a director is a partner, shareholder, member or executive officer); (v) the availability of other sources for comparable products or services; (vi) whether it is a single transaction or a series of ongoing, related transactions; and (vii) whether entering into the transaction would be consistent with the code of business conduct and ethics.

The code of business conduct and ethics described above will be adopted in connection with the closing of this offering, and as a result the transactions described above were not reviewed under such policy. The transactions described above were not approved by an independent committee of our board of directors and the terms were determined by negotiation among the parties.

Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates, including Insight Equity, on the one hand, and our partnership and our limited partners, on the other hand. The directors and officers of our general partner have fiduciary duties to manage our general partner in a manner beneficial to its owners. At the same time, our general partner has a duty to manage our partnership in a manner beneficial to us and our unitholders. The Delaware Revised Uniform Limited Partnership Act, which we refer to as the Delaware Act, provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties otherwise owed by a general partner to limited partners and the partnership. Pursuant to these provisions, our partnership agreement contains various provisions replacing the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing the duties of the general partner and the methods of resolving conflicts of interest. Our partnership agreement also specifically defines the remedies available to limited partners for actions taken that, without these defined liability standards, might constitute breaches of fiduciary duty under applicable Delaware law.

Whenever a conflict arises between our general partner or its affiliates, on the one hand, and us and our limited partners, on the other hand, our general partner will resolve that conflict. Our general partner may seek the approval of such resolution from the conflicts committee of the board of directors of our general partner, although there is no requirement that our general partner do so; under our partnership agreement, our general partner may decide to seek such approval or resolve a conflict of interest in any other way permitted by our partnership agreement, as described below, in its sole discretion. Our general partner will decide whether to refer the matter to the conflicts committee on a case-by-case basis. An independent third party is not required to evaluate the fairness of the resolution.

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

Our general partner may, but is not required to, seek the approval of such resolution from the conflicts committee of its board of directors. Any matters approved by the conflicts committee will be conclusively deemed to have been approved in good faith. If our general partner does not seek approval from the conflicts committee and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third or fourth bullet points above, then it will be presumed that, in making its decision, the board of directors acted in good faith and, in each case, in any proceeding brought by or on behalf of any limited partner or us challenging such approval, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in our partnership agreement, our general partner or the conflicts committee may consider

any factors that it determines in good faith to be appropriate when resolving a conflict. When our partnership agreement provides that someone act in good faith, it requires that person to subjectively believe that he is acting in the best interests of the partnership or meets the specified standard, for example, a transaction on terms no less favorable to the partnership than those generally being provided to or available from unrelated third parties.

Conflicts of interest could arise in the situations described below, among others.

Neither our partnership agreement nor any other agreement requires Insight Equity to pursue a business strategy that favors us or utilizes our assets or dictates what markets to pursue or grow. Directors of Insight Equity have a fiduciary duty to make these decisions in the best interests of the owners of Insight Equity, which may be contrary to our interests.

Because certain of the directors of our general partner are also directors and/or officers of Insight Equity and its affiliates, such directors may have fiduciary duties to Insight Equity that may cause them to pursue business strategies that disproportionately benefit Insight Equity, or which otherwise are not in our best interests.

Contracts between us, on the one hand, and our general partner and its affiliates, on the other, are not and will not be the result of arm's-length negotiations.

Neither our partnership agreement nor any of the other agreements, contracts and arrangements between us and our general partner and its affiliates are or will be the result of arm's-length negotiations. Our partnership agreement generally provides that any affiliated transaction, such as an agreement, contract or arrangement between us and our general partner and its affiliates that does not receive unitholder or conflicts committee approval, must be determined by our general partner to be:

Our general partner and its affiliates have no obligation to permit us to use any facilities or assets of our general partner and its affiliates, except as may be provided in contracts entered into specifically dealing with that use. Our general partner may also enter into additional contractual arrangements with any of its affiliates on our behalf. There is no obligation of our general partner and its affiliates to enter into any contracts of this kind.

Our general partner's affiliates may compete with us and neither our general partner nor its affiliates have any obligation to present business opportunities to us.

Our partnership agreement provides that our general partner is restricted from engaging in any business activities other than those incidental to its ownership of interests in us. However, affiliates of our general partner are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. Insight Equity may acquire, construct or dispose of assets (including assets relating to our lines of business) in the future without any obligation to offer us the opportunity to acquire those assets. In addition, under our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, will not apply to the general partner and its affiliates. As a result, neither the general partner nor any of its affiliates have any obligation to present business opportunities to us.

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

Our partnership agreement contains provisions that reduce the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law. 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. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples include how to allocate business opportunities among us and affiliates of our general partner, the exercise of our general partner's limited call right, the exercise of its voting rights with respect to the units it owns, whether to reset target distribution levels, and its determination whether or not to consent to any merger or consolidation of the partnership.

Our partnership agreement restricts the remedies available to our unitholders for actions taken by our general partner that might otherwise constitute breaches of its fiduciary duty under applicable Delaware law.

In addition to the provisions described above, our partnership agreement contains provisions that restrict the remedies available to our unitholders for actions that might otherwise constitute breaches of our general partner's fiduciary duty. For example, our partnership agreement:

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

Under our partnership agreement, our general partner has full power and authority to do all things, other than those items that require unitholder approval or with respect to which our general partner has sought conflicts committee approval, on such terms as it determines to be necessary or appropriate to conduct our business including, but not limited to, the following:

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.

The amount of cash that is available for distribution to our unitholders is affected by the decisions of our general partner regarding such matters as:

Our partnership agreement provides that we and our subsidiaries may borrow funds from our general partner and its affiliates. Our general partner and its affiliates may borrow funds from us, or our operating company and its operating subsidiaries.

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

We will reimburse our general partner and its affiliates for the costs incurred in managing and operating us. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us.

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

Our partnership agreement allows our general partner to determine, in good faith, any amounts to pay itself or its affiliates for any services rendered to us. Our general partner may also enter into additional contractual arrangements with any of its affiliates on our behalf. Neither our partnership agreement nor any of the other agreements, contracts or arrangements between us, on the one hand, and our general partner and its affiliates, on the other hand, that will be in effect as of the closing of this offering, will be the result of arm's-length negotiations. Similarly, agreements, contracts or arrangements between us and our general partner and its affiliates that are entered into following the closing of this offering may not be negotiated on an arm's-length basis, although, in some circumstances, our general partner may determine that the conflicts committee of our general partner may make a determination on our behalf with respect to such arrangements.

Our general partner will determine, in good faith, the terms of any such transactions entered into after the closing of this offering.

Our general partner and its affiliates will have no obligation to permit us to use any of its or its affiliates' facilities or assets, except as may be provided in contracts entered into specifically for such use. There is no obligation of our general partner or its affiliates to enter into any contracts of this kind.

Our general partner intends to limit its liability regarding our obligations.

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

Our general partner may exercise its right to call and purchase common units, as provided in our partnership agreement, or may assign this right to one of its affiliates or to us. Our general partner is not bound by fiduciary duty restrictions in determining whether to exercise this right. As a result, a

common unitholder may be required to sell his common units at an undesirable time or price. Please read "The Partnership Agreement—Limited Call Right" beginning on page 199.

Our general partner controls the enforcement of its and its affiliates' obligations to us.

Any agreements between us, on the one hand, and our general partner and its affiliates, on the other hand, will not grant to the unitholders, separate and apart from us, the right to enforce the obligations of our general partner and its affiliates in our favor.

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

The attorneys, independent accountants and others who have performed services for us regarding this offering have been retained by our general partner. Attorneys, independent accountants and others who perform services for us are selected by our general partner or the conflicts committee and may perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the holders of common units in the event of a conflict of interest between our general partner and its affiliates, on the one hand, and us or the holders of common units, on the other hand, depending on the nature of the conflict. We do not intend to do so in most cases.

The Delaware Act provides that Delaware limited partnerships may, in their partnership agreements, modify, restrict or expand the fiduciary duties otherwise owed by a general partner to limited partners and the partnership.

Pursuant to these provisions, our partnership agreement contains various provisions replacing the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing the duties of the general partner and the methods of resolving conflicts of interest. We have adopted these provisions to allow our general partner or its affiliates to engage in transactions with us that would otherwise be prohibited or restricted by state-law fiduciary duty standards and to take into account the interests of other parties in addition to our interests when resolving conflicts of interest. We believe this is appropriate and necessary because our general partner's board of directors will have fiduciary duties to manage our general partner in a manner that is beneficial to its owners, as well as to our unitholders. Without these provisions, our general partner's ability to make decisions involving conflicts of interest would be restricted. These provisions benefit our general partner by enabling it to take into consideration all parties involved in the proposed action, so long as the resolution is "fair and reasonable" to us. These provisions also enable our general partner to attract and retain experienced and capable directors. These provisions are detrimental to our unitholders because they restrict the remedies available to unitholders for actions that, without those provisions, might constitute breaches of fiduciary duty, as described below, and permit our general partner to take into account the interests of third parties in addition to our interests when resolving conflicts of interest. The following is a summary of:

The following table summarizes the differences between the default fiduciary duties that would apply to our general partner under the Delaware Act and the contractual duties of our general partner under our partnership agreement.


State-law fiduciary duties		Partnership agreement standards
General standard: Act in good faith and with due care and loyalty.		Standard when acting in its capacity as our general partner: Act in good faith.
Due care: Use the amount of care that an ordinarily careful and prudent person would use in similar circumstances and consider all material information reasonably available in making business decisions.
Loyalty: Do not take any action taking any action or engage in any transaction where a conflict of interest is present unless such transaction is entirely fair to the partnership.		Standard for resolving conflicts of interest: Any matters approved by the conflicts committee will be conclusively deemed to have been approved in good faith. Affiliated transactions and resolutions of conflicts of interest that are not approved by a vote of common unitholders and that are not approved by the conflicts committee of the board of directors of our general partner must be determined by 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 • "fair and reasonable" to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us. If our general partner does not seek approval from the conflicts committee and the board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the bullet points above, then it will be presumed that, in making its decision, the general partner acted in good faith. 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 that presumption. Standard when acting in its individual capacity: No duty to the partnership or the unitholders whatsoever, other than the implied contractual covenant of good faith and fair dealing.


Consultation with advisers: Our general partner may consult with legal counsel, accountants, investment bankers and other consultants and advisers selected by it, and in any action shall be fully protected from liability to us or our partners in relying in good faith upon the advice or opinion of such persons as to matters that the general partner reasonably believes to be within such person's professional or expert competence.		Consultation with advisers: Same as state-law standard.
Rights and remedies of unitholders: A limited partner generally may institute legal action on behalf of the partnership to recover damages from a third party where a general partner has refused to institute the action or where an effort to cause a general partner to do so is not likely to succeed. In addition, the statutory or case law of some jurisdictions may permit a limited partner to institute legal action on behalf of himself and all other similarly situated limited partners to recover damages from a general partner for violations of its fiduciary duties, if any, to the limited partners. A partner or other person shall not be liable to a limited partnership or to another partner or to another person that is a party to or is otherwise bound by a partnership agreement for breach of fiduciary duty for the partner's or other person's good faith reliance on the provisions of the partnership agreement.		Rights and remedies of unitholders: Our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners for errors of judgment or for any acts or omissions unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that our general partner or its officers and directors acted in bad faith or engaged in fraud or willful misconduct. To the extent that, at law or in equity, an indemnitee has duties and liabilities relating thereto to us or to our partners, our general partner and any other indemnitee acting in connection with our business or affairs shall not be liable to us or to any partner for its good faith reliance on the provisions of our partnership agreement, and such reliance shall be a defense in any action relating to such duties or liabilities.

By purchasing our common units, each common unitholder automatically agrees to be bound by the provisions in our partnership agreement, including the provisions discussed above. This is in accordance with the policy of the Delaware Act favoring the principle of freedom of contract and the enforceability of partnership agreements. The failure of a limited partner to sign a partnership agreement does not render the partnership agreement unenforceable against that person.

Under our partnership agreement, we must indemnify our general partner and its officers, directors, managers and certain other specified persons, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by our general partner or these other persons. We must provide this indemnification unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that these persons acted in bad faith or engaged in fraud or willful misconduct. We must also provide this indemnification for criminal proceedings unless our general partner or these other persons acted with knowledge that their conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it meets the requirements set forth above. To the extent these provisions purport to include indemnification for liabilities arising under the Securities Act, in the opinion of the SEC, such indemnification is contrary to public policy and, therefore, unenforceable. Please read "The Partnership Agreement—Indemnification" beginning on page 202.

The common units represent limited partner interests in us. The holders of common units are entitled to participate in partnership distributions and exercise the rights or privileges available to limited partners under our partnership agreement. For a description of the relative rights and preferences of holders of common units in and to partnership distributions, please read this section and "Our Cash Distribution Policy and Restrictions on Distributions" beginning on page 64. For a description of the rights and privileges of limited partners under our partnership agreement, including voting rights, please read "The Partnership Agreement" beginning on page 190.

Duties. will serve as the registrar and transfer agent for the common units. We will pay all fees charged by the transfer agent for transfers of common units except the following that must be paid by unitholders:

There will be no charge to unitholders for disbursements of our cash distributions. We will indemnify the transfer agent, its agents and each of their stockholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.

Resignation or Removal. The transfer agent may resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If no successor is appointed, our general partner may act as the transfer agent and registrar until a successor is appointed.

Our general partner will cause any transfers to be recorded on our books and records no less frequently than quarterly.

We may, at our discretion, treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holder's rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

Common units are securities and any transfers are subject to the laws governing the transfer of securities. In addition to other rights acquired upon transfer, the transferor gives the transferee the right to become a substituted limited partner in our partnership for the transferred common units.

Until a common unit has been transferred on our books, we and the transfer agent may treat the record holder of the unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

The following is a summary of the material provisions of our partnership agreement. The form of our partnership agreement is included in this prospectus as Appendix A. We will provide prospective investors with a copy of our partnership agreement upon request at no charge.

We summarize the following provisions of our partnership agreement elsewhere in this prospectus:

We were formed in April 2012 as a Delaware limited partnership. Our partnership will have perpetual existence unless terminated pursuant to the terms of our partnership agreement.

Our purpose, as set forth in our partnership agreement, is limited to any business activity that is approved by our general partner and that lawfully may be conducted by a limited partnership organized under Delaware law; provided, that our general partner shall not cause us to engage, directly or indirectly, in any business activity that the general partner determines would be reasonably likely to cause us to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes.

Although our general partner has the ability to cause us and our subsidiaries to engage in activities other than our current operations, our general partner has no current plans to do so and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interests of us or the limited partners, other than the implied contractual covenant of good faith and fair dealing. Our general partner is generally authorized to perform all acts it determines to be necessary or appropriate to carry out our purposes and to conduct our business.

Our partnership agreement specifies the manner in which we will make cash distributions to holders of our common units and other partnership securities. For a description of these cash distribution provisions, please read "Provisions of our Partnership Agreement Relating to Cash Distributions" beginning on page 77.

Unitholders are not obligated to make additional capital contributions, except as described below under "—Limited Liability."

For a discussion of our general partner's right to contribute capital to maintain its percentage interest if we issue additional units, please read "—Issuance of Additional Partnership Interests" beginning on page 194.

The following is a summary of the unitholder vote required for approval of the matters specified below. Matters that require the approval of a "unit majority" require the approval of a majority of the common units.

In voting their common units, our general partner and its affiliates will have no duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interests of us or the limited partners, other than the implied contractual covenant of good faith and fair dealing.


Issuance of additional units		No approval right.
Amendment of our partnership agreement		Certain amendments may be made by our general partner without the approval of the unitholders. Other amendments generally require the approval of a unit majority. Please read "—Amendment of the Partnership Agreement" beginning on page 194.
Merger of our partnership or the sale of all or substantially all of our assets		Unit majority in certain circumstances. Please read "—Merger, Consolidation, Conversion, Sale or Other Disposition of Assets" beginning on page 223.
Dissolution of our partnership		Unit majority. Please read "—Dissolution" beginning on page 197.
Continuation of our business upon dissolution		Unit majority. Please read "—Dissolution" beginning on page 197.
Withdrawal of our general partner		Under most circumstances, the approval of a majority of the common units, excluding common units held by our general partner and its affiliates, is required for the withdrawal of our general partner prior to December 31, 2023 in a manner that would cause a dissolution of our partnership. Please read "—Withdrawal or Removal of Our General Partner" beginning on page 198.
Removal of our general partner		Not less than 66²/3% of the outstanding units, voting as a single class, including units held by our general partner and its affiliates. Please read "—Withdrawal or Removal of Our General Partner" beginning on page 198.

If any person or group other than our general partner and its affiliates acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units from our general partner, its affiliates, their direct transferees and their indirect transferees approved by our general partner in its sole discretion or to any person or group who acquires the units with the specific prior approval of our general partner.

Our partnership agreement is governed by Delaware law. Our partnership agreement requires that any claims, suits, actions or proceedings:

shall be exclusively brought in the Court of Chancery of the State of Delaware, regardless of whether such claims, suits, actions or proceedings sound in contract, tort, fraud or otherwise, are based on common law, statutory, equitable, legal or other grounds, or are derivative or direct claims. By purchasing a common unit, a limited partner is irrevocably consenting to these limitations and provisions regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of the Court of Chancery of the State of Delaware in connection with any such claims, suits, actions or proceedings.

Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that he otherwise acts in conformity with the provisions of the

partnership agreement, his liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital he is obligated to contribute to us for his common units plus his share of any undistributed profits and assets. However, if it were determined that the right, or exercise of the right, by the limited partners as a group:

constituted "participation in the control" of our business for the purposes of the Delaware Act, then the limited partners could be held personally liable for our obligations under the laws of Delaware, to the same extent as our general partner. This liability would extend to persons who transact business with us under the reasonable belief that the limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of our general partner. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for this type of a claim in Delaware case law.

Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would exceed the fair value of the assets of the limited partnership. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years. Under the Delaware Act, a substituted limited partner of a limited partnership is liable for the obligations of his assignor to make contributions to the partnership, except that such person is not obligated for liabilities unknown to him at the time he became a limited partner and that could not be ascertained from the partnership agreement.

Our subsidiaries conduct business in three states and we may have subsidiaries that conduct business in other states in the future. Maintenance of our limited liability as a member of the operating company may require compliance with legal requirements in the jurisdictions in which the operating company conducts business, including qualifying our subsidiaries to do business there.

Limitations on the liability of members or limited partners for the obligations of a limited liability company or limited partnership have not been clearly established in many jurisdictions. If, by virtue of our ownership interest in our operating company or otherwise, it were determined that we were conducting business in any state without compliance with the applicable limited partnership or limited liability company statute, or that the right or exercise of the right by the limited partners as a group to remove or replace our general partner, to approve some amendments to our partnership agreement, or to take other action under our partnership agreement constituted "participation in the control" of our business for purposes of the statutes of any relevant jurisdiction, then the limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as our general partner under the circumstances. We will operate in a manner that our general partner considers reasonable and necessary or appropriate to preserve the limited liability of the limited partners.

Our partnership agreement authorizes us to issue an unlimited number of additional partnership interests for the consideration and on the terms and conditions determined by our general partner without the approval of the unitholders.

It is possible that we will fund acquisitions through the issuance of additional common units or other partnership interests. Holders of any additional common units we issue will be entitled to share equally with the then-existing holders of common units in our distributions of available cash. In addition, the issuance of additional common units or other partnership interests may dilute the value of the interests of the then-existing holders of common units in our net assets.

In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership interests that, as determined by our general partner, may have special voting rights to which the common units are not entitled. In addition, our partnership agreement does not prohibit our subsidiaries from issuing equity securities, which may effectively rank senior to the common units.

Our general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units or other partnership interests whenever, and on the same terms that, we issue those interests to persons other than our general partner and its affiliates and beneficial owners, to the extent necessary to maintain the percentage interest of the general partner and its affiliates, including such interest represented by common units, that existed immediately prior to each issuance. The holders of common units will not have preemptive rights under our partnership agreement to acquire additional common units or other partnership interests.

General. Amendments to our partnership agreement may be proposed only by or with the consent of our general partner. However, our general partner will have no duty or obligation to propose any amendment and may decline to do so free of any duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interests of us or the limited partners, other than the implied contractual covenant of good faith and fair dealing. In order to adopt a proposed amendment, other than the amendments discussed below, our general partner is required to seek written approval of the holders of the number of units required to approve the amendment or to call a meeting of the limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a unit majority.

The provision of our partnership agreement preventing the amendments having the effects described in the clauses above can be amended upon the approval of the holders of at least 90.0% of the outstanding units, voting as a single class (including units owned by our general partner and its affiliates). Upon completion of the offering, affiliates of our general partner will own approximately % of our outstanding common units (approximately % if the underwriters exercise their option to purchase additional common units in full).

No unitholder approval. Our general partner may generally make amendments to our partnership agreement without the approval of any limited partner to reflect:

In addition, our general partner may make amendments to our partnership agreement, without the approval of any limited partner, if our general partner determines that those amendments:

Opinion of counsel and unitholder approval. Any amendment that our general partner determines adversely affects in any material respect one or more particular classes of limited partners will require the approval of at least a majority of the class or classes so affected, but no vote will be required by any class or classes of limited partners that our general partner determines are not adversely affected in any material respect. Any amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding units in relation to other classes of units will require the approval of at least a majority of the type or class of units so affected. Any amendment that reduces the voting percentage required to take any action, other than to remove the general partner or call a meeting, is required to be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the voting requirement sought to be reduced. Any amendment that increases the voting percentage required to remove the general partner or call a meeting of unitholders must be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the voting requirement sought to be increased. For amendments of the type not requiring unitholder approval, our general partner will not be required to obtain an opinion of counsel that an amendment will neither result in a loss of limited liability to the limited partners nor result in our being treated as a taxable entity for federal income tax purposes in connection with any of the amendments. No other amendments to our partnership agreement will become effective without the approval of holders of at least 90% of the outstanding units, voting as a single class, unless we first obtain an opinion of counsel to the effect that the amendment will not affect the limited liability under applicable law of any of our limited partners.

A merger, consolidation or conversion of us requires the prior consent of our general partner. However, our general partner will have no duty or obligation to consent to any merger, consolidation or conversion and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interest of us or the limited partners, other than the implied contractual covenant of good faith and fair dealing.

In addition, our partnership agreement generally prohibits our general partner, without the prior approval of the holders of a unit majority, from causing us to sell, exchange or otherwise dispose of all or substantially all of our assets in a single transaction or a series of related transactions. Our general partner may, however, mortgage, pledge, hypothecate or grant a security interest in all or substantially all of our assets without such approval. Our general partner may also sell all or substantially all of our assets under a foreclosure or other realization upon those encumbrances without such approval. Finally, our general partner may consummate any merger without the prior approval of our unitholders if we are the surviving entity in the transaction, our general partner has received an opinion of counsel regarding limited liability and tax matters, the transaction would not result in a material amendment to the partnership agreement (other than an amendment that the general partner could adopt without the consent of the limited partners), each of our units will be an identical unit of our partnership following the transaction and the partnership interests to be issued do not exceed 20% of our outstanding partnership interests immediately prior to the transaction.

If the conditions specified in our partnership agreement are satisfied, our general partner may convert us or any of our subsidiaries into a new limited liability entity or merge us or any of our subsidiaries into, or convey all of our assets to, a newly formed entity, if the sole purpose of that conversion, merger or conveyance is to effect a mere change in our legal form into another limited

liability entity, our general partner has received an opinion of counsel regarding limited liability and tax matters and the governing instruments of the new entity provide the limited partners and our general partner with the same rights and obligations as contained in our partnership agreement. Our unitholders are not entitled to dissenters' rights of appraisal under our partnership agreement or applicable Delaware law in the event of a conversion, merger or consolidation, a sale of substantially all of our assets or any other similar transaction or event.

We will continue as a limited partnership until dissolved under our partnership agreement. We will dissolve upon:

Upon a dissolution under the last clause above, the holders of a unit majority may also elect, within specific time limitations, to continue our business on the same terms and conditions described in our partnership agreement by appointing as a successor general partner an entity approved by the holders of units representing a unit majority, subject to our receipt of an opinion of counsel to the effect that:

Upon our dissolution, unless our business is continued, the liquidator authorized to wind up our affairs will, acting with all of the powers of our general partner that are necessary or appropriate, liquidate our assets and apply the proceeds of the liquidation as described in "Provisions of our Partnership Agreement Relating to Cash Distributions—Distributions of Cash Upon Liquidation." The liquidator may defer liquidation or distribution of our assets for a reasonable period of time or distribute assets to partners in kind if it determines that a sale would be impractical or would cause undue loss to our partners.

Except as described below, our general partner has agreed not to withdraw voluntarily as our general partner prior to December 31, 2023 without obtaining the approval of the holders of at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates, and furnishing an opinion of counsel regarding limited liability and tax matters. On or after December 31, 2023, our general partner may withdraw as general partner without first obtaining approval of any unitholder by giving 90 days' written notice, and that withdrawal will not constitute a violation of our partnership agreement. Notwithstanding the information above, our general partner may withdraw without unitholder approval upon 90 days' notice to the limited partners if at least 50% of the outstanding common units are held or controlled by one person and its affiliates, other than our general partner and its affiliates. In addition, our partnership agreement permits our general partner, in some instances, to sell or otherwise transfer all of its general partner interest in us without the approval of the unitholders. Please read "—Transfer of General Partner Interest" beginning on page 199.

Upon withdrawal of our general partner under any circumstances, other than as a result of a transfer by our general partner of all or a part of its general partner interest in us, the holders of a unit majority may select a successor to that withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless within a specified period after that withdrawal, the holders of a unit majority agree in writing to continue our business and to appoint a successor general partner. Please read "—Dissolution" beginning on page 197.

Our general partner may not be removed unless that removal is approved by the vote of the holders of not less than 66²/3% of the outstanding units, voting together as a single class, including units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of our general partner is also subject to the approval of a successor general partner by the vote of the holders of a majority of the outstanding common units, voting as a class. The ownership of more than 33¹/3% of the outstanding units by our general partner and its affiliates gives them the ability to prevent our general partner's removal. At the closing of this offering, affiliates of our general partner will own % of our outstanding common units (approximately % if the underwriters exercise their option to purchase additional common units in full).

In the event of the removal of our general partner under circumstances where cause exists or withdrawal of our general partner where that withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the general partner interest of the departing general partner for a cash payment equal to the fair market value of those interests. Under all other circumstances where our general partner withdraws or is removed by the limited partners, the departing general partner will have the option to require the successor general partner to purchase the general partner interest of the departing general partner or its affiliates for fair market value. In each case, this fair market value will be determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing general partner and the successor general partner will determine the fair market value. Or, if the departing general partner and the successor general partner cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.

If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner's general partner interest will automatically convert into common units equal to the fair market value of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.

In addition, we will be required to reimburse the departing general partner for all amounts due to the departing general partner, including, without limitation, all employee-related liabilities, including severance liabilities incurred as a result of the termination of any employees employed for our benefit by the departing general partner or its affiliates.

Under our partnership agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any common units or other partnership securities proposed to be sold by Insight Equity or its assignees if an exemption from the registration requirements is not otherwise available. These registration rights continue for two years following any withdrawal or removal of Emerge GP as our general partner. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts and commissions. Please read "Units Eligible for Future Sale" beginning on page 204.

Except for a transfer by our general partner of all, but not less than all, of its general partner interest to:

our general partner may not transfer all or any of its general partner interest to another person prior to December 31, 2023 without the approval of the holders of at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates. As a condition of this transfer, the transferee must, among other things, assume the rights and duties of our general partner, agree to be bound by the provisions of our partnership agreement and furnish an opinion of counsel regarding limited liability and tax matters.

Our general partner and its affiliates may, at any time, transfer common units to one or more persons without unitholder approval.

At any time, the owners of our general partner may sell or transfer all or part their ownership interests in our general partner to an affiliate or a third party without the approval of our unitholders.

Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove Emerge GP as our general partner or from otherwise changing our management. Please read "—Withdrawal or Removal of Our General Partner" beginning on page 199 for a discussion of certain consequences of the removal of our general partner. If any person or group, other than our general partner and its affiliates, acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply in certain circumstances. Please read "—Meetings; Voting" beginning on page 201.

If at any time our general partner and its affiliates own more than 80% of the then-issued and outstanding limited partner interests of any class, our general partner will have the right, which it may

assign in whole or in part to any of its affiliates or beneficial owners thereof or to us, to acquire all, but not less than all, of the limited partner interests of the class held by unaffiliated persons as of a record date to be selected by our general partner, on at least 10, but not more than 60, days' notice. The purchase price in the event of this purchase is the greater of:

As a result of our general partner's right to purchase outstanding limited partner interests, a holder of limited partner interests may have his limited partner interests purchased at an undesirable time or a price that may be lower than market prices at various times prior to such purchase or lower than a unitholder may anticipate the market price to be in the future. The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his common units in the market. Please read "Material Federal Income Tax Consequences—Disposition of Common Units" beginning on page 205.

If our general partner, with the advice of counsel, determines we are subject to U.S. federal, state or local laws or regulations that, in the reasonable determination of our general partner, create a substantial risk of cancellation or forfeiture of any property that we have an interest in because of the nationality, citizenship or other related status of any limited partner, then our general partner may adopt such amendments to our partnership agreement as it determines necessary or advisable to:

To avoid any adverse effect on the maximum applicable rates chargeable to customers by us under certain laws or regulations that may be applicable to our future business or operations, or in order to reverse an adverse determination that has occurred regarding such maximum rate, our partnership agreement provides our general partner the power to amend the agreement. If our general partner, with the advice of counsel, determines that our not being treated as an association taxable as a corporation or otherwise taxable as an entity for U.S. federal income tax purposes, coupled with the tax status (or lack of proof thereof) of one or more of our limited partners, has, or is reasonably likely to have, a material adverse effect on the maximum applicable rates chargeable to customers by us, then our general partner may adopt such amendments to our partnership agreement as it determines necessary or advisable to:

Except as described below regarding certain persons or groups owning 20% or more of any class of units then outstanding, record holders of units on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited.

Our general partner does not anticipate that any meeting of our unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or without a meeting, if consents in writing describing the action so taken are signed by holders of the number of units necessary to authorize or take that action at a meeting. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20% of the outstanding units of the class for which a meeting is proposed. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called, represented in person or by proxy, will constitute a quorum, unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage.

Each record holder of a unit has a vote according to his percentage interest in us, although additional limited partner interests having special voting rights could be issued. Please read "—Issuance of Additional Partnership Interests" beginning on page 194. However, if at any time any person or group, other than our general partner and its affiliates, or a direct or subsequently approved (at the time of transfer) transferee of our general partner or its affiliates and purchasers specifically approved by our general partner in its sole discretion, acquires, in the aggregate, beneficial ownership of 20% or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum or for other similar purposes. Common units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and his nominee provides otherwise.

Any notice, demand, request, report or proxy material required or permitted to be given or made to record holders of common units under our partnership agreement will be delivered to the record holder by us or by the transfer agent.

By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission are reflected in our books and records. Except as described under "—Limited Liability," the common units will be fully paid, and unitholders will not be required to make additional contributions.

Under our partnership agreement, in most circumstances, we will indemnify the following persons, to the fullest extent permitted by law, from and against all losses, claims, damages or similar events:

We must provide this indemnification unless there has been a final, non-appealable judgment by a court of competent jurisdiction determining that these persons acted in bad faith or engaged in fraud or willful misconduct. We must also provide this indemnification for criminal proceedings unless our general partner or these other persons acted with knowledge that their conduct was unlawful.

Any indemnification under these provisions will only be out of our assets. Unless our general partner otherwise agrees, it will not be personally liable for, or have any obligation to contribute or lend funds or assets to us to enable us to effectuate, indemnification. We may purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under our partnership agreement.

Our partnership agreement requires us to reimburse our general partner and its affiliates for all expenses they incur or payments they make on our behalf. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our general partner is entitled to determine in good faith the expenses that are allocable to us.

Our general partner is required to keep appropriate books of our business at our principal offices. These books will be maintained for both tax and financial reporting purposes on an accrual basis. For tax and fiscal reporting purposes, our fiscal year is the calendar year.

We will furnish or make available to record holders of our common units, within 90 days (or such shorter time as required by SEC rules) after the close of each fiscal year, an annual report containing audited consolidated financial statements and a report on those consolidated financial statements by our independent public accountants. Except for our fourth quarter, we will also furnish or make available summary financial information within 45 days (or such shorter time as required by SEC rules) after the close of each quarter. We will be deemed to have made any such report available if we file such report with the SEC on EDGAR or make the report available on a publicly available website which we maintain.

We will furnish each record holder with information reasonably required for federal and state tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to our unitholders will depend on their cooperation in supplying us with specific information. Every unitholder will receive information to assist him in determining his federal and state tax liability and in filing his federal and state income tax returns, regardless of whether he supplies us with the necessary information.

Our partnership agreement provides that a limited partner can, for a purpose reasonably related to his interest as a limited partner, upon reasonable written demand stating the purpose of such demand and at his own expense, have furnished to him:

Our general partner may, and intends to, keep confidential from the limited partners trade secrets or other information the disclosure of which our general partner believes in good faith is not in our best interests or that we are required by law or by agreements with third parties to keep confidential. In addition, the partners do not have a right to receive information from us for the purpose of determining whether to pursue litigation or assist in pending litigation against us except pursuant to applicable rules of discovery.

After the sale of the common units offered hereby, Insight Equity will hold an aggregate of common units. The sale of these units could have an adverse impact on the price of the common units or on any trading market that may develop.

The common units sold in the offering will generally be freely transferable without restriction or further registration under the Securities Act, except that any common units owned by an "affiliate" of ours may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption under Rule 144 or otherwise. Rule 144 permits securities acquired by an affiliate of the issuer to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:

Sales under Rule 144 are also subject to specific manner of sale provisions, holding period requirements, notice requirements and the availability of current public information about us. A person who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned his common units for at least six months (provided we are in compliance with the current public information requirement) or one year (regardless of whether we are in compliance with the current public information requirement), would be entitled to sell common units under Rule 144 without regard to the rule's public information requirements, volume limitations, manner of sale provisions and notice requirements.

Our partnership agreement does not restrict our ability to issue additional partnership securities. Any issuance of additional common units or other equity securities would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions to and market price of, our common units then outstanding. Please read "The Partnership Agreement—Issuance of Additional Partnership Interests" beginning on page 194.

In connection with the closing of this offering, our partnership agreement will grant Insight Equity certain demand and "piggyback" registration rights. Under the partnership agreement, Insight Equity will generally have the right to require us to file a registration statement for the public sale of all of the partnership securities in the partnership owned by it. In addition, if we sell any partnership securities in a registered underwritten offering, Insight Equity will have the right, subject to specified limitations, to include its partnership securities in that offering. We will pay all expenses relating to any demand or piggyback registration, except for underwriters or brokers' commission or discounts.

Insight Equity, our partnership, our general partner and its affiliates, including their respective executive officers and directors, have agreed not to sell any common units they beneficially own for a period of 180 days from the date of this prospectus, subject to certain exceptions. Please read "Underwriting" beginning on page 228.

This section is a summary of the material tax considerations that may be relevant to prospective unitholders who are individual citizens or residents of the United States and, unless otherwise noted in the following discussion, is the opinion of Latham & Watkins LLP, counsel to our general partner and us, insofar as it relates to legal conclusions with respect to matters of U.S. federal income tax law. This section is based upon current provisions of the Internal Revenue Code of 1986, as amended (the "Internal Revenue Code"), existing and proposed Treasury regulations promulgated under the Internal Revenue Code (the "Treasury Regulations") and current administrative rulings and court decisions, all of which are subject to change. Later changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to "us," "we" or "our" are references to Emerge Energy Services LP and our operating subsidiaries.

The following discussion does not comment on all federal income tax matters affecting us or our unitholders. Moreover, the discussion focuses on unitholders who are individual citizens or residents of the U.S. and has only limited application to corporations, estates, entities treated as partnerships for U.S. federal income tax purposes, trusts, nonresident aliens, U.S. expatriates and former citizens or long-terms residents of the United States or other unitholders subject to specialized tax treatment, such as banks, insurance companies and other financial institutions, tax-exempt institutions, foreign persons (including, without limitations, controlled foreign corporations, passive foreign investment companies and non-U.S. persons eligible for the benefits of an applicable income tax treaty with the United States), IRAs, real estate investment trusts (REITs) or mutual funds, dealers in securities or currencies, traders in securities, U.S. persons whose "functional currency" is not the U.S. dollar, persons holding their units as part of a "straddle," "hedge," "conversion transaction" or other risk reduction transaction, and persons deemed to sell their units under the constructive sale provisions of the Code. In addition, the discussion only comments, to a limited extent, on state, local and foreign tax consequences. Accordingly, we encourage each prospective unitholder to consult his own tax advisor in analyzing the federal, state, local and foreign tax consequences particular to him of the ownership or disposition of common units.

No ruling has been or will be requested from the IRS regarding our characterization as a partnership for tax purposes. Instead, we will rely on opinions of Latham & Watkins LLP. Unlike a ruling, an opinion of counsel represents only that counsel's best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made herein may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for the common units and the prices at which common units trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will result in a reduction in cash available for distribution to our unitholders and thus will be borne indirectly by our unitholders. Furthermore, the tax treatment of us, or of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.

All statements as to matters of federal income tax law and legal conclusions with respect thereto, but not as to factual matters, contained in this section, unless otherwise noted, are the opinion of Latham & Watkins LLP and are based on the accuracy of the representations made by us.

For the reasons described below, Latham & Watkins LLP has not rendered an opinion with respect to the following specific federal income tax issues: (i) the treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units (please read "—Tax Consequences of Unit Ownership—Treatment of Short Sales"); (ii) whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please read "—Disposition of Common Units—Allocations Between Transferors and Transferees"); and (iii) whether our method for depreciating Section 743 adjustments is sustainable in certain cases (please

read "—Tax Consequences of Unit Ownership—Section 754 Election" and "—Disposition of Common Units—Uniformity of Units").

A partnership is not a taxable entity and incurs no federal income tax liability. Instead, each partner of a partnership is required to take into account his share of items of income, gain, loss and deduction of the partnership in computing his federal income tax liability, regardless of whether cash distributions are made to him by the partnership. Distributions by a partnership to a partner are generally not taxable to the partnership or the partner unless the amount of cash distributed to him is in excess of the partner's adjusted basis in his partnership interest. Section 7704 of the Internal Revenue Code provides that publicly traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to as the "Qualifying Income Exception," exists with respect to publicly traded partnerships of which 90% or more of the gross income for every taxable year consists of "qualifying income." Qualifying income includes income and gains derived from the mining, exploration, production, transportation, processing, refining and storage and marketing of any mineral or natural resource, including silica sand and crude oil, natural gas and products thereof. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale or other disposition of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income. We estimate that less than % of our current gross income is not qualifying income; however, this estimate could change from time to time. Based upon and subject to this estimate, the factual representations made by us and our general partner and a review of the applicable legal authorities, Latham & Watkins LLP is of the opinion that at least 90% of our current gross income constitutes qualifying income. The portion of our income that is qualifying income may change from time to time.

No ruling has been or will be sought from the IRS and the IRS has made no determination as to our status or the status of our operating subsidiaries for federal income tax purposes or whether our operations generate "qualifying income" under Section 7704 of the Internal Revenue Code. Instead, we will rely on the opinion of Latham & Watkins LLP on such matters. It is the opinion of Latham & Watkins LLP that, based upon the Internal Revenue Code, its regulations, published revenue rulings and court decisions and the representations described below that:

In rendering its opinion, Latham & Watkins LLP has relied on factual representations made by us and our general partner. The representations made by us and our general partner upon which Latham & Watkins LLP has relied include:

We believe that these representations have been true in the past and expect that these representations will continue to be true in the future.

If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery (in which case the IRS may also require us to make adjustments with respect to our unitholders or pay other amounts), we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly formed

corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation, and then distributed that stock to the unitholders in liquidation of their interests in us. This deemed contribution and liquidation should be tax-free to unitholders and us so long as we, at that time, do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for federal income tax purposes.

If we were taxed as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction would be reflected only on our tax return rather than being passed through to our unitholders, and our net income would be taxed to us at corporate rates. In addition, any distribution made to a unitholder would be treated as taxable dividend income, to the extent of our current and accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the unitholder's tax basis in his common units, or taxable capital gain, after the unitholder's tax basis in his common units is reduced to zero. Accordingly, taxation as a corporation would result in a material reduction in a unitholder's cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the units.

The discussion below is based on Latham & Watkins LLP's opinion that we will be classified as a partnership for federal income tax purposes.

Unitholders of Emerge Energy Services LP will be treated as partners of Emerge Energy Services LP for federal income tax purposes. Also, unitholders whose common units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their common units will be treated as partners of Emerge Energy Services LP for federal income tax purposes.

A beneficial owner of common units whose units have been transferred to a short seller to complete a short sale would appear to lose his status as a partner with respect to those units for federal income tax purposes. Please read "—Tax Consequences of Unit Ownership—Treatment of Short Sales".

Income, gain, deductions or losses would not appear to be reportable by a unitholder who is not a partner for federal income tax purposes, and any cash distributions received by a unitholder who is not a partner for federal income tax purposes would therefore appear to be fully taxable as ordinary income. These holders are urged to consult their tax advisors with respect to their tax consequences of holding common units in Emerge Energy Services LP. The references to "unitholders" in the discussion that follows are to persons who are treated as partners in Emerge Energy Services LP for federal income tax purposes.

Subject to the discussion below under "—Entity-Level Collections," we will not pay any federal income tax. Instead, each unitholder will be required to report on his income tax return his share of our income, gains, losses and deductions without regard to whether we make cash distributions to him. Consequently, we may allocate income to a unitholder even if he has not received a cash distribution. Each unitholder will be required to include in income his allocable share of our income, gains, losses and deductions for our taxable year ending with or within his taxable year. Our taxable year ends on December 31.

Distributions by us to a unitholder generally will not be taxable to the unitholder for federal income tax purposes, except to the extent the amount of any such cash distribution exceeds his tax basis in his common units immediately before the distribution. Our cash distributions in excess of a unitholder's tax basis generally will be considered to be gain from the sale or exchange of the common units, taxable in accordance with the rules described under "—Disposition of Common Units." Any reduction in a unitholder's share of our liabilities for which no partner bears the economic risk of loss, known as "nonrecourse liabilities," will be treated as a distribution by us of cash to that unitholder. To the extent our distributions cause a unitholder's "at-risk" amount to be less than zero at the end of any taxable year, he must recapture any losses deducted in previous years. Please read "—Limitations on Deductibility of Losses".

A decrease in a unitholder's percentage interest in us because of our issuance of additional common units will decrease his share of our nonrecourse liabilities, and thus will result in a corresponding deemed distribution of cash. This deemed distribution may constitute a non-pro rata distribution. A non-pro rata distribution of money or property may result in ordinary income to a unitholder, regardless of his tax basis in his common units, if the distribution reduces the unitholder's share of our "unrealized receivables," including depreciation recapture, depletion recapture and/or substantially appreciated "inventory items," each as defined in the Internal Revenue Code, and collectively, "Section 751 Assets." To that extent, the unitholder will be treated as having been distributed his proportionate share of the Section 751 Assets and then having exchanged those assets with us in return for the non-pro rata portion of the actual distribution made to him. This latter deemed exchange will generally result in the unitholder's realization of ordinary income, which will equal the excess of (i) the non-pro rata portion of that distribution over (ii) the unitholder's tax basis (often zero) for the share of Section 751 Assets deemed relinquished in the exchange.

We estimate that a purchaser of common units in this offering who owns those common units from the date of closing of this offering through the record date for distributions for the period ending December 31, 2016, will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be % or less of the cash distributed with respect to that period. Thereafter, we anticipate that the ratio of allocable taxable income to cash distributions to the unitholders will increase. These estimates are based upon the assumption that gross income from operations will approximate the forecasted annual distribution on all common units and other assumptions with respect to capital expenditures, cash flow, net working capital and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, legislative, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and tax reporting positions that we will adopt and with which the IRS could disagree. Accordingly, we cannot assure you that these estimates will prove to be correct. The actual percentage of distributions that will constitute taxable income could be higher or lower than expected, and any differences could be material and could materially affect the value of the common units. For example, the ratio of allocable taxable income to cash distributions to a purchaser of common units in this offering will be greater, and perhaps substantially greater, than our estimate with respect to the period described above if:

A unitholder's initial tax basis for his common units will be the amount he paid for the common units plus his share of our nonrecourse liabilities. That basis will be increased by his share of our income and by any increases in his share of our nonrecourse liabilities. That basis will be decreased, but not below zero, by distributions from us, by the unitholder's share of our losses, by any decreases in his share of our nonrecourse liabilities and by his share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized. A unitholder will generally have a share of our nonrecourse liabilities based on his share of our profits. Please read "—Disposition of Common Units—Recognition of Gain or Loss".

The deduction by a unitholder of his share of our losses will be limited to the tax basis in his units and, in the case of an individual unitholder, estate, trust or certain closely held corporate unitholders, to the amount for which the unitholder is considered to be "at risk" with respect to our activities, if that is less than his tax basis. A common unitholder subject to these limitations must recapture losses deducted in previous years to the extent that distributions cause his at-risk amount to be less than zero at the end of any taxable year. Losses disallowed to a common unitholder or recaptured as a result of these limitations will carry forward and will be allowable as a deduction to the extent that his at-risk amount is subsequently increased, provided such losses do not exceed such common unitholder's tax basis in his common units. Upon the taxable disposition of a unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at-risk limitation but may not be offset by losses suspended by the basis limitation. Any loss previously suspended by the at-risk limitation in excess of that gain would no longer be utilizable.

In general, a unitholder will be at risk to the extent of the tax basis of his units, excluding any portion of that basis attributable to his share of our nonrecourse liabilities, reduced by (i) any portion of that basis representing amounts otherwise protected against loss because of a guarantee, stop loss agreement or other similar arrangement and (ii) any amount of money he borrows to acquire or hold his units, if the lender of those borrowed funds owns an interest in us, is related to the unitholder or can look only to the units for repayment. A unitholder's at-risk amount will increase or decrease as the tax basis of the unitholder's units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in his share of our nonrecourse liabilities.

In addition to the basis and at-risk limitations on the deductibility of losses, the passive loss limitations generally provide that individuals, estates, trusts and some closely-held corporations and personal service corporations can deduct losses from passive activities, which are generally trade or business activities in which the taxpayer does not materially participate, only to the extent of the taxpayer's income from those passive activities. The passive loss limitations are applied separately with respect to each publicly traded partnership. Consequently, any passive losses we generate will only be available to offset our passive income generated in the future and will not be available to offset income from other passive activities or investments, including our investments or a unitholder's investments in other publicly traded partnerships, or the unitholder's salary, active business or other income. Passive losses that are not deductible because they exceed a unitholder's share of income we generate may be deducted in full when he disposes of his entire investment in us in a fully taxable transaction with an unrelated party. The passive loss limitations are applied after other applicable limitations on deductions, including the at-risk rules and the basis limitation.

A unitholder's share of our net income may be offset by any of our suspended passive losses, but it may not be offset by any other current or carryover losses from other passive activities, including those attributable to other publicly traded partnerships.

The deductibility of a non-corporate taxpayer's "investment interest expense" is generally limited to the amount of that taxpayer's "net investment income." Investment interest expense includes:

The computation of a unitholder's investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment or (if applicable) qualified dividend income. The IRS has indicated that the net passive income earned by a publicly traded partnership will be treated as investment income to its unitholders. In addition, the unitholder's share of our portfolio income will be treated as investment income.

If we are required or elect under applicable law to pay any federal, state, local or foreign income tax on behalf of any unitholder or any former unitholder, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the unitholder on whose behalf the payment was made. If the payment is made on behalf of a person whose identity cannot be determined, we are authorized to treat the payment as a distribution to all current unitholders. We are authorized to amend our partnership agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under our partnership agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of an individual unitholder in which event the unitholder would be required to file a claim in order to obtain a credit or refund.

In general, if we have a net profit, our items of income, gain, loss and deduction will be allocated among our unitholders in accordance with their percentage interests in us. Although we do not expect that our operations will result in the creation of negative accounts, if negative capital accounts nevertheless result, items of our income and gain will be allocated in an amount and manner sufficient to eliminate the negative balance as quickly as possible.

Specified items of our income, gain, loss and deduction will be allocated to account for (i) any difference between the tax basis and fair market value of our assets at the time of an offering and (ii) any difference between the tax basis and fair market value of any property contributed to us, together referred to in this discussion as the "Contributed Property." The effect of these allocations, referred to as Section 704(c) Allocations, to a unitholder purchasing common units from us in this offering will be essentially the same as if the tax bases of our assets were equal to their fair market values at the time of this offering. In the event we issue additional common units or engage in certain other transactions in the future, "reverse Section 704(c) Allocations," similar to the Section 704(c)

Allocations described above, will be made to our unitholders immediately prior to such issuance or other transactions to account for the difference between the "book" basis for purposes of maintaining capital accounts and the fair market value of all property held by us at the time of such issuance or future transaction. In addition, items of recapture income will be allocated to the extent possible to the unitholder who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of ordinary income by some unitholders.

An allocation of items of our income, gain, loss or deduction, other than an allocation required by the Internal Revenue Code to eliminate the difference between a partner's "book" capital account, credited with the fair market value of Contributed Property, and "tax" capital account, credited with the tax basis of Contributed Property, referred to in this discussion as the "Book-Tax Disparity," will generally be given effect for federal income tax purposes in determining a partner's share of an item of income, gain, loss or deduction only if the allocation has "substantial economic effect." In any other case, a partner's share of an item will be determined on the basis of his interest in us, which will be determined by taking into account all the facts and circumstances, including:

Latham & Watkins LLP is of the opinion that, with the exception of the issues described in "—Section 754 Election," "—Disposition of Common Units—Uniformity of Units" and "—Disposition of Common Units—Allocations Between Transferors and Transferees," allocations under our partnership agreement will be given effect for federal income tax purposes in determining a partner's share of an item of income, gain, loss or deduction.

A unitholder whose units are loaned to a "short seller" to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period:

Because there is no direct or indirect controlling authority on the issue relating to partnership interests, Latham & Watkins LLP has not rendered an opinion regarding the tax treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units; therefore, 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 modify any applicable brokerage account agreements to prohibit their brokers from borrowing and loaning their units. The IRS has previously announced that it is studying issues relating to the tax treatment of short sales of partnership interests. Please also read "—Disposition of Common Units—Recognition of Gain or Loss".

Each unitholder will be required to take into account his distributive share of any items of our income, gain, loss or deduction for purposes of the alternative minimum tax. The current minimum tax

rate for non-corporate taxpayers is 26% on the first $179,500 of alternative minimum taxable income in excess of the exemption amount and 28% on any additional alternative minimum taxable income. Prospective unitholders are urged to consult with their tax advisors as to the impact of an investment in units on their liability for the alternative minimum tax.

Beginning on January 1, 2013, the highest marginal U.S. federal income tax rate applicable to ordinary income of individuals is 39.6% and the highest marginal U.S. federal income tax rate applicable to long-term capital gains (generally, capital gains on certain assets held for more than twelve months) of individuals is 20%. However, these rates are subject to change by new legislation at any time.

In addition, a 3.8% Medicare tax, or NIIT, on certain net investment income earned by individuals, estates and trusts applies for taxable years beginning after December 31, 2012. For these purposes, net investment income generally includes a unitholder's allocable share of our income and gain realized by a unitholder from a sale of units. In the case of an individual, the tax will be imposed on the lesser of (i) the unitholder's net investment income or (ii) the amount by which the unitholder's modified adjusted gross income exceeds $250,000 (if the unitholder is married and filing jointly or a surviving spouse), $125,000 (if the unitholder is married and filing separately) or $200,000 (in any other case). In the case of an estate or trust, the tax will be imposed on the lesser of (i) undistributed net investment income, or (ii) the excess adjusted gross income over the dollar amount at which the highest income tax bracket applicable to an estate or trust begins. Recently, the U.S. Department of the Treasury and the IRS issued proposed Treasury Regulations that provide guidance regarding the NIIT. Although the proposed Treasury Regulations are effective for taxable years beginning after December 31, 2013, taxpayers may rely on the proposed Treasury Regulations for purposes of compliance until the effective date of the final regulations. Prospective unitholders are urged to consult with their tax advisors as to the impact of the NIIT on an investment in our common units.

We will make the election permitted by Section 754 of the Internal Revenue Code. That election is irrevocable without the consent of the IRS unless there is a constructive termination of the partnership. Please read "—Disposition of Common Units—Constructive Termination". The election will generally permit us to adjust a common unit purchaser's tax basis in our assets ("inside basis") under Section 743(b) of the Internal Revenue Code to reflect his purchase price. This election does not apply with respect to a person who purchases common units directly from us. The Section 743(b) adjustment belongs to the purchaser and not to other unitholders. For purposes of this discussion, the inside basis in our assets with respect to a unitholder will be considered to have two components: (i) his share of our tax basis in our assets ("common basis") and (ii) his Section 743(b) adjustment to that basis.

We will adopt the remedial allocation method as to all our properties. Where the remedial allocation method is adopted, the Treasury Regulations under Section 743 of the Internal Revenue Code require a portion of the Section 743(b) adjustment that is attributable to recovery property that is subject to depreciation under Section 168 of the Internal Revenue Code and whose book basis is in excess of its tax basis to be depreciated over the remaining cost recovery period for the property's unamortized Book-Tax Disparity. Under Treasury Regulation Section 1.167(c)-1(a)(6), a Section 743(b) adjustment attributable to property subject to depreciation under Section 167 of the Internal Revenue Code, rather than cost recovery deductions under Section 168, is generally required to be depreciated using either the straight-line method or the 150% declining balance method. Under our partnership agreement, our general partner is authorized to take a position to preserve the uniformity of units even if that position is not consistent with these and any other Treasury Regulations. Please read "—Disposition of Common Units—Uniformity of Units".

We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the property's unamortized Book-Tax Disparity, or treat that portion as non-amortizable to the extent attributable to property which is not amortizable. This method is consistent with the methods employed by other publicly traded partnerships but is arguably inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. To the extent this Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may take a depreciation or amortization position under which all purchasers acquiring units in the same month would receive depreciation or amortization, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. This kind of aggregate approach may result in lower annual depreciation or amortization deductions than would otherwise be allowable to some unitholders. Please read "—Disposition of Common Units—Uniformity of Units". A unitholder's tax basis for his common units is reduced by his share of our deductions (whether or not such deductions were claimed on an individual's income tax return) so that any position we take that understates deductions will overstate the common unitholder's basis in his common units, which may cause the unitholder to understate gain or overstate loss on any sale of such units. Please read "—Disposition of Common Units—Recognition of Gain or Loss". Latham & Watkins LLP is unable to opine as to whether our method for depreciating Section 743 adjustments is sustainable for property subject to depreciation under Section 167 of the Internal Revenue Code or if we use an aggregate approach as described above, as there is no direct or indirect controlling authority addressing the validity of these positions. Moreover, the IRS may challenge our position with respect to depreciating or amortizing the Section 743(b) adjustment we take to preserve the uniformity of the units. If such a challenge were sustained, the gain from the sale of units might be increased without the benefit of additional deductions.

A Section 754 election is advantageous if the transferee's tax basis in his units is higher than the units' share of the aggregate tax basis of our assets immediately prior to the transfer. In that case, as a result of the election, the transferee would have, among other items, a greater amount of depreciation deductions and his share of any gain or loss on a sale of our assets would be less. Conversely, a Section 754 election is disadvantageous if the transferee's tax basis in his units is lower than those units' share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the units may be affected either favorably or unfavorably by the election. A basis adjustment is required regardless of whether a Section 754 election is made in the case of a transfer of an interest in us if we have a substantial built-in loss immediately after the transfer, or if we distribute property and have a substantial basis reduction. Generally, a built-in loss or a basis reduction is substantial if it exceeds $250,000.

The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. For example, the allocation of the Section 743(b) adjustment among our assets must be made in accordance with the Internal Revenue Code. The IRS could seek to reallocate some or all of any Section 743(b) adjustment allocated by us to our tangible assets to goodwill instead. Goodwill, as an intangible asset, is generally non-amortizable or amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure you that the determinations we make will not be successfully challenged by the IRS and that the deductions resulting from them will not be reduced or disallowed altogether. Should the IRS require a different basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than he would have been allocated had the election not been revoked.

We use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in income his share of our income, gain, loss and deduction for our taxable year ending within or with his taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of his units following the close of our taxable year but before the close of his taxable year must include his share of our income, gain, loss and deduction in income for his taxable year, with the result that he will be required to include in income for his taxable year his share of more than twelve months of our income, gain, loss and deduction. Please read "—Disposition of Common Units—Allocations Between Transferors and Transferees".

The tax basis of our assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. The federal income tax burden associated with the difference between the fair market value of our assets and their tax basis immediately prior to (i) this offering will be borne by affiliates of our general partner and (ii) any other offering will be borne by our unitholders as of that time. Please read "—Disposition of Common Units—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction".

To the extent allowable, we may elect to use the depreciation and cost recovery methods, including bonus depreciation to the extent available, that will result in the largest deductions being taken in the early years after assets subject to these allowances are placed in service. Please read "—Disposition of Common Units—Uniformity of Units". Property we subsequently acquire or construct may be depreciated using accelerated methods permitted by the Internal Revenue Code.

If we dispose of depreciable property by sale, foreclosure or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of his interest in us. Please read "—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction" and "—Disposition of Common Units—Recognition of Gain or Loss".

The costs we incur in selling our units (called "syndication expenses") must be capitalized and cannot be deducted currently, ratably or upon our termination. There are uncertainties regarding the classification of costs as organization expenses, which may be amortized by us, and as syndication expenses, which may not be amortized by us. The underwriting discounts and commissions we incur will be treated as syndication expenses.

The federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values, and the initial tax bases, of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deductions previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

In general, we are entitled to depletion deductions with respect to silica sand mined from the underlying mineral property. We generally are entitled to the greater of cost depletion limited to the basis of the property or percentage depletion. The percentage depletion rate for silica sand is 5%.

Depletion deductions we claim generally will reduce the tax basis of the underlying mineral property. Depletion deductions can, however, exceed the total tax basis of the mineral property. The excess of our percentage depletion deductions over the adjusted tax basis of the property at the end of the taxable year is subject to tax preference treatment in computing the alternative minimum tax. Please read "—Tax Consequences of Unit Ownership—Alternative Minimum Tax." Upon the disposition of the mineral property, a portion of the gain, if any, equal to the lesser of the deductions for depletion which reduce the adjusted tax basis of the mineral property plus deductible development and mining exploration expenses (discussed below), or the amount of gain realized upon the disposition, will be treated as ordinary income to us.

We will elect to currently deduct mining exploration expenditures that we pay or incur to determine the existence, location, extent or quality of silica sand deposits prior to the time the existence of silica sand in commercially marketable quantities has been disclosed.

If a mine reaches the producing stage in any taxable year, amounts we deducted for mine exploration expenditures must be recaptured and reduce future depletion deductions by the amount of the recapture, as described below. In the alternative, we may elect, in such taxable year and with respect to all such mines reaching the producing stage during such taxable year, to include such amount in our taxable income. A mine reaches the producing stage when the major part of the silica sand production is obtained from working mines rather than those opened for the purpose of development or the principal activity of the mine is the production of developed silica sand rather than the development of additional silica sand for mining. Assuming the election described above is not made, this recapture is accomplished through the disallowance of both cost and percentage depletion deductions on the particular mine reaching the producing stage. This disallowance of depletion deductions continues until the amount of adjusted exploration expenditures with respect to the mine has been fully recaptured. This recapture is not applied to the full amount of the previously deducted exploration expenditures. Instead these expenditures are reduced by the amount of percentage depletion, if any, that was lost as a result of deducting these exploration expenditures.

We generally will elect to defer mine development expenses, consisting of expenditures incurred in making silica sand accessible for extraction, after the exploration process has disclosed the existence of silica sand in commercially marketable quantities, and deduct them on a ratable basis as the silica sand benefited by the expenses is sold.

Mine exploration and development expenditures are subject to recapture as ordinary income to the extent of any gain upon a sale or other disposition of our property or of your common units. Please read "—Disposition of Common Units." Corporate unitholders are subject to an additional rule that requires them to capitalize a portion of their otherwise deductible mine exploration and development expenditures. Corporate unitholders, other than some S corporations, are required to reduce their otherwise deductible exploration expenditures by 30%. These capitalized mine exploration and development expenditures must be amortized over a 60-month period, beginning in the month paid or incurred, using a straight-line method and may not be treated as part of the basis of the property for purposes of computing depletion.

When computing the alternative minimum tax, mine exploration and development expenditures are capitalized and deducted over a ten-year period beginning with the taxable year in which the

expenditures were made. Unitholders may avoid this alternative minimum tax adjustment of their mine exploration and development expenditures by electing to capitalize all or part of the expenditures and deducting them over ten years for regular income tax purposes. You may select the specific amount of these expenditures for which you wish to make this election.

If any silica sand reserves are sold or otherwise disposed of in a taxable transaction, we will recognize gain or loss measured by the difference between the amount realized (including the amount of any indebtedness assumed by the purchaser upon such disposition or to which such property is subject) and the adjusted tax basis of the property sold. Generally, the character of any gain or loss recognized upon that disposition will depend upon whether our silica sand reserves or the mined silica sand sold are held by us:

In determining dealer status with respect to silica sand reserves and other types of real estate, the courts have identified a number of factors for distinguishing between a particular property held for sale in the ordinary course of business and one held for investment. Any determination must be based on all the facts and circumstances surrounding the particular property and sale in question.

We intend to hold our silica sand reserves for use in a trade or business and achieve long-term capital appreciation. Although our general partner may consider strategic sales of silica sand reserves consistent with achieving long-term capital appreciation, our general partner does not anticipate frequent sales of silica sand reserves. Thus, the general partner does not believe we will be viewed as a dealer. In light of the factual nature of this question, however, there is no assurance that our purposes for holding our properties will not change and that our future activities will not cause us to be a "dealer" in silica sand reserves.

If we are not a dealer with respect to our silica sand reserves and we have held the disposed property for more than a one-year period primarily for use in our trade or business, the character of any gain or loss realized from a disposition of the property will be determined under Section 1231 of the Internal Revenue Code. If we have not held the property for more than one year at the time of the sale, gain or loss from the sale will be taxable as ordinary income.

A unitholder's distributive share of any Section 1231 gain or loss generated by us will be aggregated with any other gains and losses realized by that unitholder from the disposition of property used in the trade or business, as defined in Section 1231(b) of the Internal Revenue Code, and from the involuntary conversion of such properties and of capital assets held in connection with a trade or business or a transaction entered into for profit for the requisite holding period. If a net gain results, all such gains and losses will be long-term capital gains and losses; if a net loss results, all such gains and losses will be ordinary income and losses. Net Section 1231 gains will be treated as ordinary income to the extent of prior net Section 1231 losses of the taxpayer or predecessor taxpayer for the five most recent prior taxable years to the extent such losses have not previously been offset against Section 1231 gains. Losses are deemed recaptured in the chronological order in which they arose.

If we are not a dealer with respect to our silica sand reserves and that property is not used in a trade or business, the property will be a "capital asset" within the meaning of Section 1221 of the Internal Revenue Code. Gain or loss recognized from the disposition of that property will be taxable as

capital gain or loss, and the character of such capital gain or loss as long-term or short-term will be based upon our holding period of such property at the time of its sale. The requisite holding period for long-term capital gain is more than one year.

Upon a disposition of silica sand reserves, a portion of the gain, if any, equal to the lesser of (1) the depletion deductions that reduced the tax basis of the disposed mineral property plus deductible development and mining exploration expenses or (2) the amount of gain recognized on the disposition, will be treated as ordinary income to us.

Subject to the limitations on the deductibility of losses discussed above and the limitation discussed below, unitholders will be entitled to a deduction, herein referred to as the Section 199 deduction, equal to a specified percentage of our qualified production activities income that is allocated to such unitholder. The percentage is currently 9% for qualified production activities income.

Qualified production activities income is generally equal to gross receipts from domestic production activities reduced by cost of goods sold allocable to those receipts, other expenses directly associated with those receipts, and a share of other deductions, expenses and losses that are not directly allocable to those receipts or another class of income. The products produced must be manufactured, produced, grown or extracted in whole or in significant part by the taxpayer in the United States.

For a partnership, the Section 199 deduction is determined at the partner level. To determine his Section 199 deduction, each unitholder will aggregate his share of the qualified production activities income allocated to him from us with the unitholder's qualified production activities income from other sources. Each unitholder must take into account his distributive share of the expenses allocated to him from our qualified production activities regardless of whether we otherwise have taxable income. However, our expenses that otherwise would be taken into account for purposes of computing the Section 199 deduction are only taken into account if and to the extent the unitholder's share of losses and deductions from all of our activities is not disallowed by the basis rules, the at-risk rules or the passive activity loss rules. Please read "—Tax Consequences of Unit Ownership—Limitations on Deductibility of Losses."

The amount of a unitholder's Section 199 deduction for each year is limited to 50% of the IRS Form W-2 wages actually or deemed paid by the unitholder during the calendar year that are deducted in arriving at qualified production activities income. Each unitholder is treated as having been allocated IRS Form W-2 wages from us equal to the unitholder's allocable share of our wages that are deducted in arriving at qualified production activities income for that taxable year. It is not anticipated that we or our subsidiaries will pay material wages that will be allocated to our unitholders, and thus a unitholder's ability to claim the Section 199 deduction may be limited.

Gain or loss will be recognized on a sale of units equal to the difference between the amount realized and the unitholder's tax basis for the units sold. A unitholder's amount realized will be measured by the sum of the cash or the fair market value of other property received by him plus his share of our nonrecourse liabilities. Because the amount realized includes a unitholder's share of our nonrecourse liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.

Prior distributions from us that in the aggregate were in excess of cumulative net taxable income for a common unit and, therefore, decreased a unitholder's tax basis in that common unit will, in effect,

become taxable income if the common unit is sold at a price greater than the unitholder's tax basis in that common unit, even if the price received is less than his original cost.

Except as noted below, gain or loss recognized by a unitholder, other than a "dealer" in units, on the sale or exchange of a unit will generally be taxable as capital gain or loss. Capital gain recognized by an individual on the sale of units held for more than twelve months will generally be taxed at the U.S. federal income tax rate applicable to long-term capital gains. However, a portion of this gain or loss, which will likely be substantial, will be separately computed and taxed as ordinary income or loss under Section 751 of the Internal Revenue Code to the extent attributable to assets giving rise to depreciation recapture or other "unrealized receivables" or to "inventory items" we own. The term "unrealized receivables" includes potential recapture items, including depreciation recapture. Ordinary income attributable to unrealized receivables, inventory items and depreciation recapture may exceed net taxable gain realized upon the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and a capital loss upon a sale of units. Capital losses may offset capital gains and no more than $3,000 of ordinary income, in the case of individuals, and may only be used to offset capital gains in the case of corporations.

The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an "equitable apportionment" method, which generally means that the tax basis allocated to the interest sold equals an amount that bears the same relation to the partner's tax basis in his entire interest in the partnership as the value of the interest sold bears to the value of the partner's entire interest in the partnership. Treasury Regulations under Section 1223 of the Internal Revenue Code allow a selling unitholder who can identify common units transferred with an ascertainable holding period to elect to use the actual holding period of the common units transferred. Thus, according to the ruling discussed above, a common unitholder will be unable to select high or low basis common units to sell as would be the case with corporate stock, but, according to the Treasury Regulations, he may designate specific common units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of common units transferred must consistently use that identification method for all subsequent sales or exchanges of common units. A unitholder considering the purchase of additional units or a sale of common units purchased in separate transactions is urged to consult his tax advisor as to the possible consequences of this ruling and application of the Treasury Regulations.

Specific provisions of the Internal Revenue Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an "appreciated" partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:

in each case, with respect to the partnership interest or substantially identical property.

Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is also authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.

In general, our taxable income and losses will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month, which we refer to in this prospectus as the "Allocation Date." However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business will be allocated among the unitholders on the Allocation Date in the month in which that gain or loss is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.

Although simplifying conventions are contemplated by the Internal Revenue Code and most publicly traded partnerships use similar simplifying conventions, the use of this method may not be permitted under existing Treasury Regulations as there is no direct or indirect controlling authority on this issue. The Department of the Treasury and the IRS have issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders, although such tax items must be prorated on a daily basis. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. Existing publicly traded partnerships are entitled to rely on these proposed Treasury Regulations; however, they are not binding on the IRS and are subject to change until final Treasury Regulations are issued. Accordingly, Latham & Watkins LLP is unable to opine on the validity of this method of allocating income and deductions between transferor and transferee unitholders because the issue has not been finally resolved by the IRS or the courts. If this method is not allowed under the Treasury Regulations, or only applies to transfers of less than all of the unitholder's interest, our taxable income or losses might be reallocated among the unitholders. We are authorized to revise our method of allocation between transferor and transferee unitholders, as well as unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations. A unitholder who owns units at any time during a quarter and who disposes of them prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deductions attributable to that quarter but will not be entitled to receive that cash distribution.

A unitholder who sells any of his units is generally required to notify us in writing of that sale within 30 days after the sale (or, if earlier, January 15 of the year following the sale). A purchaser of units who purchases units from another unitholder is also generally required to notify us in writing of that purchase within 30 days after the purchase. Upon receiving such notifications, we are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. Failure to notify us of a purchase may, in some cases, lead to the imposition of penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the U.S. and who effects the sale or exchange through a broker who will satisfy such requirements.

We will be considered to have been terminated for tax purposes if there are sales or exchanges which, in the aggregate, constitute 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of measuring whether the 50% threshold is reached, multiple sales of the same interest are counted only once. A constructive termination results in the closing of our taxable year for all unitholders. 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 result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. A constructive termination occurring on a date other than December 31 will result in us filing two tax

returns (and unitholders could receive two Schedules K-1 if the relief discussed below is not available) for one fiscal year and the cost of the preparation of these returns will be borne by all common unitholders. We would be required to make new tax elections after a termination, including a new election under Section 754 of the Internal Revenue Code, and a termination would result in a deferral of our deductions for depreciation. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a termination might either accelerate the application of, or subject us to, any tax legislation enacted before the termination. The IRS has recently announced a publicly traded partnership technical termination relief procedure whereby if a publicly traded partnership that has technically terminated requests publicly traded partnership technical termination relief and the IRS grants such relief, among other things, the partnership will only have to provide one Schedule K-1 to unitholders for the year notwithstanding two partnership tax years.

Because we cannot match transferors and transferees of units, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory. A lack of uniformity can result from a literal application of Treasury Regulation Section 1.167(c)-1(a)(6). Any non-uniformity could have a negative impact on the value of the units. Please read "—Tax Consequences of Unit Ownership—Section 754 Election". We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the property's unamortized Book-Tax Disparity, or treat that portion as non-amortizable, to the extent attributable to property the common basis of which is not amortizable, consistent with the regulations under Section 743 of the Internal Revenue Code, even though that position may be inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. Please read "—Tax Consequences of Unit Ownership—Section 754 Election". To the extent that the Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may adopt a depreciation and amortization position under which all purchasers acquiring units in the same month would receive depreciation and amortization deductions, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. If this position is adopted, it may result in lower annual depreciation and amortization deductions than would otherwise be allowable to some unitholders and risk the loss of depreciation and amortization deductions not taken in the year that these deductions are otherwise allowable. This position will not be adopted if we determine that the loss of depreciation and amortization deductions will have a material adverse effect on the unitholders. If we choose not to utilize this aggregate method, we may use any other reasonable depreciation and amortization method to preserve the uniformity of the intrinsic tax characteristics of any units that would not have a material adverse effect on the unitholders. In either case, and as stated above under "—Tax Consequences of Unit Ownership—Section 754 Election," Latham & Watkins LLP has not rendered an opinion with respect to these methods. Moreover, the IRS may challenge any method of depreciating the Section 743(b) adjustment described in this paragraph. If this challenge were sustained, the uniformity of units might be affected, and the gain from the sale of units might be increased without the benefit of additional deductions. Please read "—Disposition of Common Units—Recognition of Gain or Loss".

Ownership of units by employee benefit plans, other tax-exempt organizations, non-resident aliens, foreign corporations and other foreign persons raises issues unique to those investors and, as described

below to a limited extent, may have substantially adverse tax consequences to them. If you are a tax-exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our common units. Employee benefit plans and most other organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of our income allocated to a unitholder that is a tax-exempt organization will be unrelated business taxable income and will be taxable to it.

Non-resident aliens and foreign corporations, trusts or estates that own units will be considered to be engaged in business in the U.S. because of the ownership of units. As a consequence, they will be required to file federal tax returns to report their share of our income, gain, loss or deduction and pay federal income tax at regular rates on their share of our net income or gain. Moreover, under rules applicable to publicly traded partnerships, our quarterly distribution to foreign unitholders will be subject to withholding at the highest applicable effective tax rate. Each foreign unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8BEN or applicable substitute form in order to obtain credit for these withholding taxes. A change in applicable law may require us to change these procedures.

In addition, because a foreign corporation that owns units will be treated as engaged in a U.S. trade or business, that corporation may be subject to the U.S. branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our earnings and profits, as adjusted for changes in the foreign corporation's "U.S. net equity," that is effectively connected with the conduct of a U.S. trade or business. That tax may be reduced or eliminated by an income tax treaty between the U.S. and the country in which the foreign corporate unitholder is a "qualified resident." In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Internal Revenue Code.

A foreign unitholder who sells or otherwise disposes of a common unit will be subject to U.S. federal income tax on gain realized from the sale or disposition of that unit to the extent the gain is effectively connected with a U.S. trade or business of the foreign unitholder. Under a ruling published by the IRS, interpreting the scope of "effectively connected income," a foreign unitholder would be considered to be engaged in a trade or business in the U.S. by virtue of the U.S. activities of the partnership, and part or all of that unitholder's gain would be effectively connected with that unitholder's indirect U.S. trade or business. Moreover, under the Foreign Investment in Real Property Tax Act, a foreign common unitholder generally will be subject to U.S. federal income tax upon the sale or disposition of a common unit if (i) he owned (directly or constructively applying certain attribution rules) more than 5% of our common units at any time during the five-year period ending on the date of such disposition and (ii) 50% or more of the fair market value of all of our assets consisted of U.S. real property interests at any time during the shorter of the period during which such unitholder held the common units or the five-year period ending on the date of disposition. Currently, more than 50% of our assets consist of U.S. real property interests and we do not expect that to change in the foreseeable future. Therefore, foreign unitholders may be subject to U.S. federal income tax on gain from the sale or disposition of their units.

Recent changes in law may affect certain foreign unitholders. Please read "—Administrative Matters—Additional Withholding Requirements."

We intend to furnish to each unitholder, within 90 days after the close of each calendar year, specific tax information, including a Schedule K-1, which describes his share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been

mentioned earlier, to determine each unitholder's share of income, gain, loss and deduction. We cannot assure you that those positions will yield a result that conforms to the requirements of the Internal Revenue Code, Treasury Regulations or administrative interpretations of the IRS. Neither we nor Latham & Watkins LLP can assure prospective unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.

The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year's tax liability, and possibly may result in an audit of his return. Any audit of a unitholder's return could result in adjustments not related to our returns as well as those related to our returns.

Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Internal Revenue Code requires that one partner be designated as the "Tax Matters Partner" for these purposes. Our partnership agreement names Emerge GP as our Tax Matters Partner.

The Tax Matters Partner has made and will make some elections on our behalf and on behalf of unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go forward, and each unitholder with an interest in the outcome may participate. The Tax Matters Partner may select the forum for judicial review, and if the Tax Matters Partner selects the Court of Federal Claims or a District Court, rather than the Tax Court, partners may be required to pay any deficiency asserted by the IRS before judicial review is available.

A unitholder must file a statement with the IRS identifying the treatment of any item on his federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.

Withholding taxes may apply to certain types of payments made to "foreign financial institutions" (as specially defined in the Internal Revenue Code) and certain other non-U.S. entities. Specifically, a 30% withholding tax may be imposed on interest, dividends and other fixed or determinable annual or periodical gains, profits and income from sources within the United States ("FDAP Income"), or gross proceeds from the sale or other disposition of any property of a type which can produce interest or dividends from sources within the United States ("Gross Proceeds") paid to a foreign financial institution or to a "non-financial foreign entity" (as specifically defined in the Internal Revenue Code), unless (i) the foreign financial institution undertakes certain diligence and reporting, (ii) the non-financial foreign entity either certifies it does not have any substantial U.S. owners or furnishes identifying information regarding each substantial U.S. owner or (iii) the foreign financial institution or non-financial foreign entity otherwise qualifies for an exemption from these rules. If the payee is a foreign financial institution and is subject to the diligence and reporting requirements in clause (i) above, it must enter into an agreement with the U.S. Treasury requiring, among other things, that it undertake to identify accounts held by certain U.S. persons or U.S.-owned foreign entities, annually

report certain information about such accounts, and withhold 30% on payments to non-compliant foreign financial institutions and certain other account holders.

These rules will generally apply to payments of FDAP Income made on or after January 1, 2014 and to payments of relevant Gross Proceeds made on or after January 1, 2017. Thus, to the extent we have FDAP Income or Gross Proceeds after these dates that are not treated as effectively connected with a U.S. trade or business (please read "—Tax-Exempt Organizations and Other Investors"), unitholders who are foreign financial institutions or certain other non-US entities may be subject to withholding on distributions they receive from us, or their distributive share of our income, pursuant to the rules described above.

Prospective investors should consult their own tax advisors regarding the potential application of these withholding provisions to their investment in our common units.

Persons who hold an interest in us as a nominee for another person are required to furnish to us:

Brokers and financial institutions are required to furnish additional information, including whether they are U.S. persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $100 per failure, up to a maximum of $1,500,000 per calendar year, is imposed by the Internal Revenue Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.

An additional tax equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the Internal Revenue Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith regarding that portion.

For individuals, a substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10% of the tax required to be shown on the return for the taxable year or $5,000 ($10,000 for most corporations). The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:

If any item of income, gain, loss or deduction included in the distributive shares of unitholders might result in that kind of an "understatement" of income for which no "substantial authority" exists, we must disclose the pertinent facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns and to take other actions as may be appropriate to permit unitholders to avoid liability for this penalty. More stringent rules apply to "tax shelters," which we do not believe includes us, or any of our investments, plans or arrangements.

A substantial valuation misstatement exists if (i) the value of any property, or the adjusted basis of any property, claimed on a tax return is 150% or more of the amount determined to be the correct amount of the valuation or adjusted basis, (ii) the price for any property or services (or for the use of property) claimed on any such return with respect to any transaction between persons described in Internal Revenue Code Section 482 is 200% or more (or 50% or less) of the amount determined under Section 482 to be the correct amount of such price, or (iii) the net Internal Revenue Code Section 482 transfer price adjustment for the taxable year exceeds the lesser of $5 million or 10% of the taxpayer's gross receipts. No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for most corporations). If the valuation claimed on a return is 200% or more than the correct valuation or certain other thresholds are met, the penalty imposed increases to 40%. We do not anticipate making any valuation misstatements.

In addition, the 20% accuracy-related penalty also applies to any portion of an underpayment of tax that is attributable to transactions lacking economic substance. To the extent that such transactions are not disclosed, the penalty imposed is increased to 40%. Additionally, there is no reasonable cause defense to the imposition of this penalty to such transactions.

If we were to engage in a "reportable transaction," we (and possibly you and others) would be required to make a detailed disclosure of the transaction to the IRS. A transaction may be a reportable transaction based upon any of several factors, including the fact that it is a type of tax avoidance transaction publicly identified by the IRS as a "listed transaction" or that it produces certain kinds of losses for partnerships, individuals, S corporations, and trusts in excess of $2 million in any single year, or $4 million in any combination of six successive tax years. Our participation in a reportable transaction could increase the likelihood that our federal income tax information return (and possibly your tax return) would be audited by the IRS. Please read "—Information Returns and Audit Procedures".

Moreover, if we were to participate in a reportable transaction with a significant purpose to avoid or evade tax, or in any listed transaction, you may be subject to the following additional consequences:

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 units.

In addition to federal income taxes, you likely will be subject to other taxes, such as state, local and foreign income taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that may be imposed by the various jurisdictions in which we do business or own property or in which you are a resident. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on his investment in us. We will initially own property or do business in Texas, Alabama and Wisconsin. All of these states also impose an income tax on corporations and other entities, and Alabama and Wisconsin also impose a personal income tax on individuals. We may also own property or do business in other jurisdictions in the future. Although you may not be required to file a return and pay taxes in some jurisdictions because your income from that jurisdiction falls below the filing and payment requirement, you will be required to file income tax returns and to pay income taxes in many of these jurisdictions in which we do business or own property and may be subject to penalties for failure to comply with those requirements. In some jurisdictions, tax losses may not produce a tax benefit in the year incurred and may not be available to offset income in subsequent taxable years. Some of the jurisdictions may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the jurisdiction. Withholding, the amount of which may be greater or less than a particular unitholder's income tax liability to the jurisdiction, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld will be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Please read "—Tax Consequences of Unit Ownership—Entity Level Collections". Based on current law and our estimate of our future operations, our general partner anticipates that any amounts required to be withheld will not be material.

It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent states, localities and foreign jurisdictions, of his investment in us. Accordingly, each prospective unitholder is urged to consult his own tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all state, local and foreign, as well as U.S. federal tax returns, that may be required of him. Latham & Watkins LLP has not rendered an opinion on the state, local or foreign tax consequences of an investment in us.

An investment in us by an employee benefit plan is subject to additional considerations because the investments of these plans may be subject to the fiduciary responsibility and prohibited transaction provisions of ERISA and the restrictions imposed by Section 4975 of the Internal Revenue Code and provisions under any federal, state, local, non-U.S. or other laws or regulations that are similar to such provisions of the Internal Revenue Code or ERISA (collectively, "Similar Laws"). For these purposes the term "employee benefit plan" includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans, Keogh plans, simplified employee pension plans and tax deferred annuities or individual retirement accounts or annuities ("IRAs") established or maintained by an employer or employee organization, and entities whose underlying assets are considered to include "plan assets" of such plans, accounts and arrangements. Among other things, consideration should be given to:

The person with investment discretion with respect to the assets of an employee benefit plan, often called a fiduciary, should determine whether an investment in us is authorized by the appropriate governing instrument and is a proper investment for the plan.

Section 406 of ERISA and Section 4975 of the Internal Revenue Code prohibit employee benefit plans and IRAs that are not considered part of an employee benefit plan, from engaging in specified transactions involving "plan assets" with parties that, with respect to the plan, are "parties in interest" under ERISA or "disqualified persons" under the Internal Revenue Code unless an exemption is available. A party in interest or disqualified person who engages in a non-exempt prohibited transaction may be subject to excise taxes and other penalties and liabilities under ERISA and the Internal Revenue Code. In addition, the fiduciary of the ERISA plan that engaged in such a non-exempt prohibited transaction may be subject to penalties and liabilities under ERISA and the Internal Revenue Code.

In addition to considering whether the purchase of common units is a prohibited transaction, a fiduciary should consider whether the plan will, by investing in us, be deemed to own an undivided interest in our assets, with the result that our general partner would also be a fiduciary of such plan and our operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Internal Revenue Code, ERISA and any other applicable Similar Laws.

The Department of Labor regulations provide guidance with respect to whether, in certain circumstances, the assets of an entity in which employee benefit plans acquire equity interests would be

deemed "plan assets." Under these regulations, an entity's assets would not be considered to be "plan assets" if, among other things:

Our assets should not be considered "plan assets" under these regulations because it is expected that the investment will satisfy the requirements in (i) and (ii) above.

In light of the serious penalties imposed on persons who engage in prohibited transactions or other violations, plan fiduciaries contemplating a purchase of common units should consult with their own counsel regarding the consequences under ERISA, the Internal Revenue Code and other Similar Laws.

Citigroup Global Markets Inc., Wells Fargo Securities, LLC and J.P. Morgan Securities LLC are acting as joint book-running managers of this offering and as representatives of the underwriters named below. Subject to the terms and conditions stated in the underwriting agreement dated the date of this prospectus, each underwriter named below has severally agreed to purchase, and we have agreed to sell to that underwriter, the number of common units set forth opposite the underwriter's name.

The underwriting agreement provides that the obligations of the underwriters to purchase the common units included in this offering are subject to approval of legal matters by counsel and to other conditions. The underwriters are obligated to purchase all the common units (other than those covered by the underwriters' over-allotment option described below) if they purchase any of the common units.

Common units sold by the underwriters to the public will initially be offered at the initial public offering price set forth on the cover of this prospectus. Any common units sold by the underwriters to securities dealers may be sold at a discount from the initial public offering price not to exceed $ per common unit. If all the common units are not sold at the initial offering price, the underwriters may change the offering price and the other selling terms. The representatives have advised us that the underwriters do not intend to make sales to discretionary accounts.

If the underwriters sell more common units than the total number set forth in the table above, we have granted to the underwriters an option, exercisable for 30 days from the date of this prospectus, to purchase up to additional common units at the public offering price less the underwriting discount. The underwriters may exercise the option solely for the purpose of covering over-allotments, if any, in connection with this offering. To the extent the option is exercised, each underwriter must purchase a number of additional common units approximately proportionate to that underwriter's initial purchase commitment. Any common units issued or sold under the option will be issued and sold on the same terms and conditions as the other common units that are the subject of this offering. If the underwriters exercise their option to purchase additional common units in full, the additional net proceeds will be approximately $ million. All of the net proceeds from any exercise of such option will be used to make an additional cash distribution to Insight Equity and other private investors. Any remaining common units not purchased by the underwriters pursuant to any exercise of the option will be issued to Insight Equity and the other private investors at the expiration of the option period, and we will not receive additional consideration from them for the issuance to them of these units.

We, the officers and directors of our general partner, and our other unitholders, including our general partner, Emerge Energy Services Holdings LLC and its affiliates, have agreed that, subject to certain exceptions, for a period of 180 days from the date of this prospectus, we and they will not, without the prior written consent of Citigroup Global Markets Inc., dispose of or hedge any common units or any securities convertible into or exchangeable for our common units. Citigroup Global Markets Inc. in its sole discretion may release any of the securities subject to these lock-up agreements at any time, which, in the case of officers and directors, shall be with notice. Notwithstanding the foregoing, if (i) during the last 17 days of the 180-day restricted period, we issue an earnings release or material news or a material event relating to our partnership occurs; or (ii) prior to the expiration of the 180-day restricted period, we announce that we will release earnings results during the 16-day

period beginning on the last day of the 180-day restricted period, the restrictions described above shall continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release or the occurrence of the material news or material event.

Prior to this offering, there has been no public market for our common units. Consequently, the initial public offering price for the common units will be determined by negotiations among us and the representatives. Among the factors that will be considered in determining the initial public offering price are our results of operations, our current financial condition, our future prospects, our markets, the economic conditions in and future prospects for the industry in which we compete, our management, and currently prevailing general conditions in the equity securities markets, including current market valuations of publicly traded companies considered comparable to our partnership. We cannot assure you, however, that the price at which the common units will sell in the public market after this offering will not be lower than the initial public offering price or that an active trading market in our common units will develop and continue after this offering.

The following table shows the underwriting discounts and commissions that we are to pay to the underwriters in connection with this offering. These amounts are shown assuming both no exercise and full exercise of the underwriters' over-allotment option.

We will pay Citigroup Global Markets Inc. an aggregate structuring fee equal to % of the gross proceeds of this offering for the evaluation, analysis and structuring of our partnership.

We estimate that the expenses of this offering, not including the underwriting discount and structuring fee, will be approximately $ million, all of which will be paid by us.

In connection with this offering, the underwriters may purchase and sell common units in the open market. Purchases and sales in the open market may include short sales, purchases to cover short positions, which may include purchases pursuant to the underwriters' over-allotment option, and stabilizing purchases.

Purchases to cover short positions and stabilizing purchases, as well as other purchases by the underwriters for their own accounts, may have the effect of preventing or retarding a decline in the market price of the common units. They may also cause the price of the common units to be higher than the price that would otherwise exist in the open market in the absence of these transactions. The underwriters may conduct these transactions on the NYSE, in the over-the-counter market or otherwise. If the underwriters commence any of these transactions, they may discontinue them at any time.

The underwriters are full service financial institutions engaged in various activities, which may include securities trading, commercial and investment banking, financial advisory, investment management, principal investment, hedging, financing and brokerage activities. Certain of the underwriters and their respective affiliates have in the past performed commercial banking, investment banking and advisory services for us, Insight Equity and our respective affiliates from time to time for which they have received customary fees and reimbursement of expenses and may, from time to time, engage in transactions with and perform services for us, Insight Equity and our respective affiliates in the ordinary course of their business for which they may receive customary fees and reimbursement of expenses. In the ordinary course of their various business activities, the underwriters and their respective affiliates may make or hold a broad array of investments and actively trade debt and equity securities (or related derivative securities) and financial instruments (which may include bank loans and/or credit default swaps) for their own account and for the accounts of their customers and may at any time hold long and short positions in such securities and instruments. Such investment and securities activities may involve our securities and instruments. An affiliate of Citigroup Global Markets Inc. is a lender under AEC Holdings' credit facility and will receive a portion of the net proceeds from this offering. In addition, an affiliate of Citigroup Global Markets Inc. owns an approximate 4.4% interest in AEC Holdings.

Because the Financial Industry Regulatory Authority, Inc., or FINRA, views the common units offered hereby as interests in a direct participation program, this offering is being made in compliance with Rule 2310 of the FINRA Rules. Investor suitability with respect to the common units should be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.

We, Insight Equity, our general partner and certain of our affiliates have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act, or to contribute to payments the underwriters may be required to make because of any of those liabilities.

In relation to each member state of the European Economic Area that has implemented the Prospectus Directive (each, a relevant member state), other than Germany, with effect from and including the date on which the Prospectus Directive is implemented in that relevant member state (the relevant implementation date), an offer of common units described in this prospectus may not be made to the public in that relevant member state other than:

provided that no such offer of common units shall require us or any underwriter to publish a prospectus pursuant to Article 3 of the Prospectus Directive.

For purposes of this provision, the expression an "offer of securities to the public" in any relevant member state means the communication in any form and by any means of sufficient information on the terms of the offer and the common units to be offered so as to enable an investor to decide to purchase or subscribe for the common units, as the expression may be varied in that member state by any measure implementing the Prospectus Directive in that member state, and the expression "Prospectus Directive" means Directive 2003/71/EC (and amendments thereto, including the 2010 PD Amending Directive, to the extent implemented in the relevant member state) and includes any relevant implementing measure in the relevant member state. The expression 2010 PD Amending Directive means Directive 2010/73/EU.

We have not authorized and do not authorize the making of any offer of common units through any financial intermediary on our behalf, other than offers made by the underwriters with a view to the final placement of the common units as contemplated in this prospectus. Accordingly, no purchaser of the common units, other than the underwriters, is authorized to make any further offer of the common units on behalf of us or the underwriters.

Our partnership may constitute a "collective investment scheme" as defined by section 235 of the Financial Services and Markets Act 2000 ("FSMA") that is not a "recognised collective investment scheme" for the purposes of FSMA ("CIS") and that has not been authorized or otherwise approved. As an unregulated scheme, it cannot be marketed in the United Kingdom to the general public, except in accordance with FSMA. This prospectus is only being distributed in the United Kingdom to, and is only directed at:

This prospectus has not been prepared in accordance with the requirements for a securities or sales prospectus under the German Securities Prospectus Act (Wertpapierprospektgesetz), the German Sales Prospectus Act (Verkaufsprospektgesetz) or the German Investment Act (Investmentgesetz). Neither the German Federal Financial Services Supervisory Authority (Bundesanstalt für Finanzdienstleistungsaufsicht—BaFin) nor any other German authority has been notified of the intention to distribute the common units in Germany. Consequently, the common units may not be distributed in Germany by way of public offering, public advertisement or in any similar manner and this prospectus and any other document relating to this offering, as well as information or statements contained therein, may not be supplied to the public in Germany or used in connection with any offer for subscription of the common units to the public in Germany or any other means of public marketing. The common units are being offered and sold in Germany only to qualified investors which are referred to in Section 3, paragraph 2 no. 1 in connection with Section 2 no. 6 of the German Securities Prospectus Act, Section 8f paragraph 2 no. 4 of the German Sales Prospectus Act and in Section 2 paragraph 11 sentence 2 no.1 of the German Investment Act. This prospectus is strictly for use of the person who has received it. It may not be forwarded to other persons or published in Germany.

This offering does not constitute an offer to sell or the solicitation of an offer to buy the common units in any circumstances in which such offer or solicitation is unlawful.

The common units may not be offered or sold, directly or indirectly, in the Netherlands, other than to qualified investors (gekwalificeerde beleggers) within the meaning of Article 1:1 of the Dutch Financial Supervision Act (Wet op het financieel toezicht).

This prospectus is being communicated in Switzerland to a small number of selected investors only. Each copy of this prospectus is addressed to a specifically named recipient and may not be copied, reproduced, distributed or passed on to third parties. The common units are not being offered to the public in Switzerland, and neither this prospectus, nor any other offering materials relating to the common units may be distributed in connection with any such public offering.

Our partnership has not been registered with the Swiss Financial Market Supervisory Authority FINMA as a foreign collective investment scheme pursuant to Article 120 of the Collective Investment Schemes Act of June 23, 2006 ("CISA"). Accordingly, the common units may not be offered to the public in or from Switzerland, and neither this prospectus, nor any other offering materials relating to the common units may be made available through a public offering in or from Switzerland. The common units may only be offered and this prospectus may only be distributed in or from Switzerland by way of private placement exclusively to qualified investors (as this term is defined in the CISA and its implementing ordinance).

The validity of the common units will be passed upon for us by Latham & Watkins LLP, Houston, Texas. Certain legal matters in connection with the common units offered hereby will be passed upon for the underwriters by Vinson & Elkins L.L.P., Houston, Texas.

The consolidated financial statements of Emerge Energy Services LP as of and for the period ended December 31, 2012 and the consolidated financial statements of SSS, AEC and Direct Fuels as of and for the years ended December 31, 2010, 2011 and 2012 have been included herein and in the registration statement in reliance upon the reports of BDO USA, LLP, independent registered public accounting firm, appearing elsewhere herein and in the registration statement, upon the authority of said firm as experts in accounting and auditing.

The information included in this prospectus relating to the estimates of our proven recoverable reserves associated with our mining operations in New Auburn, Wisconsin is derived from reserve reports prepared by Short Elliot Hendrickson Inc., an independent mining and geological consulting firm. This information is included in this prospectus upon the authority of said firm as an expert.

The information included in this prospectus relating to the estimates of our proven recoverable reserves associated with our mining operations in Barron, Wisconsin is derived from reserve reports prepared by Cooper Engineering Company, Inc., an independent mining and geological consulting firm. This information is included in this prospectus upon the authority of said firm as an expert.

The information included in this prospectus relating to the estimates of our proven recoverable reserves associated with our mining operations in Kosse, Texas is derived from reserve reports prepared by Westward Environmental, Inc., an independent mining and geological consulting firm. This information is included in this prospectus upon the authority of said firm as an expert.

We have filed with the SEC a registration statement on Form S-1 regarding the common units. This prospectus does not contain all of the information found in the registration statement. For further information regarding us and the common units offered by this prospectus, you may desire to review the full registration statement, including its exhibits and schedules, filed under the Securities Act. The registration statement of which this prospectus forms a part, including its exhibits and schedules, may be inspected and copied at the public reference room maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Copies of the materials may also be obtained from the SEC at prescribed rates by writing to the public reference room maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. You may obtain information on the operation of the public reference room by calling the SEC at 1-800-SEC-0330. The SEC maintains a web site on the Internet at http://www.sec.gov. Our registration statement, of which this prospectus constitutes a part, can be downloaded from the SEC's web site.

We intend to furnish our unitholders annual reports containing our audited financial statements and furnish or make available quarterly reports containing our unaudited interim financial information for the first three fiscal quarters of each of our fiscal years.

Some of the information in this prospectus may contain forward-looking statements. These statements can be identified by the use of forward-looking terminology including "may," "believe," "expect," "intend," "anticipate," "estimate," "continue," or other similar words. These statements discuss future expectations, contain projections of results of operations or of financial condition, or

state other "forward-looking" information. These forward-looking statements can be affected by assumptions used or by known risks or uncertainties. Consequently, no forward-looking statements can be guaranteed. When considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this prospectus. The risk factors and other factors noted throughout this prospectus could cause our actual results to differ materially from those contained in any forward-looking statement. You are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:

All forward-looking statements are expressly qualified in their entirety by the foregoing cautionary statements.

EMERGE ENERGY SERVICES LP

UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS

Set forth below are the unaudited pro forma condensed combined balance sheets of Emerge Energy Services LP (the "Partnership") as of December 31, 2012 and the unaudited pro forma condensed combined statements of operations of the Partnership for the year ended December 31, 2012. References to "we," "us" and "our" mean the Partnership and its combined subsidiaries, unless the context otherwise requires. The unaudited pro forma condensed combined financial statements for the Partnership have been derived from the unaudited pro forma condensed consolidated financial statements of Superior Silica Holdings LLC ("SSS") and AEC Holdings LLC ("AEC Holdings"),which together comprise our predecessor for accounting purposes (the "Predecessor"), and the historical consolidated and condensed consolidated financial statements of Direct Fuels Partners, L.P. ("DF"), set forth elsewhere in this prospectus and are qualified in their entirety by reference to such historical consolidated financial statements and related notes contained therein. The unaudited pro forma condensed combined financial statements have been prepared on the basis that the Partnership will be treated as a partnership for U.S. federal income tax purposes. The unaudited pro forma condensed combined financial statements should be read in conjunction with the accompanying notes and with the historical consolidated and condensed consolidated financial statements and related notes set forth elsewhere in this prospectus.

The Partnership will own and operate the businesses of the Predecessor and DF effective with the closing of the Partnership's initial public offering. The contribution of the Predecessor's business to us will be recognized at its historical basis as it is considered to be a reorganization of entities under common control. The Partnership's acquisition of Insight Equity Acquisition Partners, L.P. ("Direct Fuels") will be recognized at the fair value of the assets and liabilities contributed and will apply business combination accounting to the Partnership. For the purposes of the pro forma condensed combined balance sheet, December 31, 2012 has been used as the acquisition date of Direct Fuels. For the purposes of these pro forma condensed combined statements of operations, January 1, 2012 has been used as the acquisition date of Direct Fuels. The pro forma combined financial statements give pro forma effect to the matters set forth in the notes to these unaudited pro forma condensed combined financial statements.

The unaudited pro forma balance sheets and the unaudited pro forma statements of operations were derived by adjusting the historical unaudited pro forma condensed combined financial statements of the Predecessor. The adjustments are based upon currently available information and certain estimates and assumptions; therefore, actual adjustments will differ from the pro forma adjustments. However, management believes that the assumptions provide a reasonable basis for presenting the significant effects of the contemplated transaction and that the pro forma adjustments give appropriate effect to those assumptions and are properly applied in the pro forma combined financial information.

The unaudited pro forma condensed combined financial statements may not be indicative of the results that actually would have occurred if the Partnership had assumed the operations of the Predecessor and Direct Fuels on the dates indicated or that would be obtained in the future.

EMERGE ENERGY SERVICES LP

UNAUDITED PRO FORMA CONDENSED COMBINED BALANCE SHEET

As of December 31, 2012

(in thousands)

	Predecessor Historical		Direct Fuels Historical

ASSETS
Current assets
Cash and cash equivalents	$	1,465	$	2,544		(a)
						(b)
						(c)
						(d)
						(e)
Trade accounts receivable, net		26,781		10,773	—		37,554
Other receivables		—		4,628	—		4,628
Inventories		22,848		6,425	64	(n)	29,337
Current portion of direct financing lease receivable		1,579		—	—		1,579
Prepaid expenses and other current assets		2,602		946	—		3,548

Total Current Assets		55,275		25,316
Property, plant and equipment, net		120,851		8,743	9,884	(f)	139,478
Mineral resources, net		10,563		—	—		10,563
Intangible assets, net		1,426		—	4,815	(g)	6,241
Goodwill		—		—	74,684	(h)	74,684
Deferred debt financing, public offering costs, and other assets, net		7,672		1,367	(563	)(o)	8,476

Total Assets	$	195,787	$	35,426

LIABILITIES AND PARTNERS' EQUITY
Current liabilities
Accounts payable		27,541		10,829	—		38,370
Accrued liabilities		7,278		1,635	—		8,913
Deferred revenue		801		—	—
Derivative financial instruments		—		33	—
Current portion of long-term debt		9,321		17,067		(i)
Current portion of capital lease liability		1,548		—	—		1,548
Current portion of advances from customers		4,043		—	—		4,043

Total Current Liabilities		50,532		29,564	—
Long-term debt, net of current portion		129,640		—	7,446	(i)(d)
Capital lease liability, net of current portion		5,428		—	—		5,428
Asset retirement obligations		690		—	—		690

Total Liabilities		186,290		29,564
PARTNERS' EQUITY
Previous partners' equity		—		5,862
Predecessor equity		9,497		—
Partners' equity		—		—	81,438	(j)
Common unitholders		—		—		(k)
General partner		—		—		(k)(e)

Total Partners' Equity		9,497		5,862

Total Liabilities and Partners' Equity	$	195,787	$	35,426

See accompanying notes to unaudited pro forma condensed combined financial statements.

EMERGE ENERGY SERVICES LP

UNAUDITED PRO FORMA CONDENSED COMBINED STATEMENT OF OPERATIONS

For the Year Ended December 31, 2012

(in thousands, except per unit amounts)

	Predecessor Historical			Direct Fuels Historical			Transaction Adjustments			Partnership Pro Forma

REVENUES
Revenues	$	619,087		$	332,172		$	—		$	951,259
Other revenues		5,009			595			—			5,604

		624,096			332,767			—			956,863

OPERATING EXPENSES
Cost of product		556,718			312,704			—			869,422
Operations and maintenance		18,686			2,465			—			21,151
Depreciation, depletion and amortization		9,119			1,032			1,699	(l)(m)		11,850
Selling, general and administrative expenses		10,150			3,812			—			13,962
Provision for bad debts		57			—			—			57
Loss on disposal of equipment		(28	)		—			—			(28	)

		594,702			320,013			1,699			916,414

Income from operations		29,394			12,754			(1,699	)		40,449

OTHER EXPENSE (INCOME)
Interest expense		11,432			1,165			—	(o)		12,597
Litigation settlement expense		750			—			—			750
Changes in fair value of interest rate swap		—			(46	)		—			(46	)
Other		(145	)		—			—			(145	)

		12,037			1,119			—			13,156

Income before taxes		17,357			11,635			(1,699	)		27,293
Provision for state margin taxes		81			82			—			163

Net income	$	17,276		$	11,553		$	(1,699	)	$	27,130

Common unitholder's interest in net income
Net income per common unit (basic and diluted)
Weighted average number of common units outstanding

See accompanying notes to unaudited pro forma condensed combined financial statements.

EMERGE ENERGY SERVICES LP

NOTES TO UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS

(in thousands, except per unit amounts)

The unaudited pro forma condensed combined financial statements have been derived from the historical consolidated financial statements of SSH and AEC Holdings, which together comprise our predecessor for accounting purposes (the "Predecessor") and the acquisition of Direct Fuels, included elsewhere in this prospectus.

The pro forma adjustments have been prepared as if the combination of SSS and AEC Holdings, the acquisition of DF and the completion of this offering had taken place on December 31, 2012 for the unaudited pro forma condensed combined balance sheet and January 1, 2012 for the unaudited pro forma condensed combined statements of operations, for the year ended December 31, 2012. All of the assets and liabilities acquired by us will be recognized at their fair value based on management's

NOTES TO UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS (Continued)

estimates with the assistance from third party valuations. The unaudited pro forma combined statements of operations have been prepared on the basis that the Partnership will be treated as a partnership for U.S. federal income tax purposes.

The unaudited pro forma condensed combined financial information does not include the estimated $3.5 million of incremental general and administrative expenses we expect to incur annually as a result of becoming a publicly traded partnership, including expenses associated with annual and quarterly reporting, tax return and Schedule K-1 preparation and distribution expenses, Sarbanes-Oxley compliance expenses, expenses associated with listing on the NYSE, independent auditor fees, legal fees, investor relations expenses, registrar and transfer agent fees, outside director fees and director and officer liability insurance expenses.

NOTES TO UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS (Continued)

Pro forma net income (loss) per unit is determined by dividing the pro forma net income that would have been allocated, in accordance with the provisions of the Partnership's partnership agreement, to the common unitholders, by the number of common units expected to be outstanding at the closing of this offering. For purposes of this calculation, it is assumed that only the cash available for distribution is distributed and the number of common units outstanding was . All units were assumed to have been outstanding since January 1, 2012. Basic and diluted pro forma net income (loss) per unit are equivalent as there are no dilutive units at the date of closing of the initial public offering of the common units.

EMERGE ENERGY SERVICES LP

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We have audited the accompanying consolidated balance sheet of Emerge Energy Services LP (a Delaware limited partnership) (the "Partnership") as of December 31, 2012 and the related consolidated statements of operations, partners' equity (deficit) and cash flows from inception (April 27, 2012) through the period ended December 31, 2012. These financial statements are the responsibility of Partnership management. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit 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 audit 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 presentation of the financial statements. We believe that our audit provides 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, 2012, and the results of its operations and its cash flows from inception (April 27, 2012) through the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America.

EMERGE ENERGY SERVICES LP

CONSOLIDATED STATEMENT OF OPERATIONS

From inception (April 27, 2012) through the period ended December 31, 2012

EMERGE ENERGY SERVICES LP

CONSOLIDATED STATEMENT OF PARTNERS' EQUITY (DEFICIT)

From inception (April 27, 2012) through the period ended December 31, 2012

EMERGE ENERGY SERVICES LP

CONSOLIDATED STATEMENT OF CASH FLOWS

From inception (April 27, 2012) through the period ended December 31, 2012

Emergent Energy Services LP is a Delaware limited partnership and was organized on April 27, 2012. Emergent Energy Services Operating LLC is a Delaware limited liability company formed on April 27, 2012 to become the operating subsidiary of the Emergent Energy Services LP. Emergent Energy Services GP LLC is a Delaware limited liability company formed on April 27, 2012 to become the general partner of Emergent Energy Services LP. On July 20, 2012, Emergent Energy Services LP changed its name to Emerge Energy Services LP; Emergent Energy Services Operating LLC changed its name to Emerge Energy Services Operating LLC ("OLLC"); and Emergent Energy Services GP LLC (the "General Partner") changed its name to Emerge Energy Services GP LLC. Emerge Energy Services LP and OLLC are collectively hereinafter referred to as the "Partnership."

On April 27, 2012, Superior Silica Resources LLC ("SSR"), a Texas limited liability company, pledged to contribute $1,960 to the Partnership in exchange for a 98% limited partner interest, and the General Partner pledged to contribute $40 to the Partnership in exchange for a 2% general partner interest. Prior to October 31, 2012, the pledged amounts were received by the Partnership in cash.

The Partnership intends to issue and sell common units to the public through an initial public offering. In connection with this initial public offering, the Partnership will contribute its equity interests in certain subsidiaries to OLLC.

The consolidated financial statements include the accounts of Emerge Energy Services LP and its wholly owned subsidiary OLLC and have been prepared in accordance with accounting principles generally accepted in the United States of America. All intercompany balances and transactions have been eliminated in consolidation. The only activity since inception (April 27, 2012) is the funding from the general and limited partners and compensation expense.

Related party payables represent advances from Emerge Energy Services GP LLC to the Partnership. These advances are non-interest bearing and mature on demand. The related party payables recorded for compensation cost incurred during November and December 2012 amounted to $81,673.

The Partnership evaluated subsequent events through the date that the financial statements were issued. No significant events have occurred requiring disclosure.

Set forth below are the unaudited pro forma condensed combined balances sheets of Superior Silica Holdings LLC ("SSH") and AEC Holdings LLC ("AEC Holdings"), which together comprise our predecessor for accounting purposes (the "Predecessor"), as of December 31, 2012, 2011 and 2010 and the unaudited pro forma condensed combined statements of operations of the Predecessor for the years ended December 31, 2012, 2011 and 2010. The unaudited pro forma condensed combined financial statements for the Predecessor have been derived from the historical consolidated financial statements of SSH and AEC Holdings which are included elsewhere in this prospectus and are qualified in their entirety by reference to such historical consolidated financial statements and related notes contained therein. The unaudited pro forma condensed combined financial statements have been prepared on the basis that the Predecessor will be treated as a limited liability company for U.S. federal income tax purposes. The unaudited pro forma condensed combined financial statements should be read in conjunction with the accompanying notes and with the historical consolidated financial statements of SSS and AEC Holdings and related notes set forth elsewhere in this Prospectus.

The unaudited pro forma condensed combined financial statements give pro forma effect to the matters set forth in the notes to these unaudited pro forma condensed combined financial statements.

The unaudited pro forma condensed combined balance sheets and statements of operations were derived by adjusting the historical consolidated financial statements of SSH and AEC Holdings. The adjustments are based upon currently available information and certain estimates and assumptions; therefore, actual adjustments will differ from the pro forma adjustments. However, management believes that the assumptions provide a reasonable basis for presenting the significant effects of the contemplated transaction and that the pro forma adjustments give appropriate effect to those assumptions and are properly applied in the pro forma combined financial information.

The unaudited pro forma condensed combined financial statements may not be indicative of the results that actually would have occurred if the Predecessor had been consolidated on the dates indicated or that would be obtained in the future.

PREDECESSOR

UNAUDITED PRO FORMA CONDENSED COMBINED BALANCE SHEET

As of December 31, 2012

(in thousands)

	SSS Historical			AEC Historical		Transaction Adjustments			Predecessor Pro Forma

ASSETS
Current assets
Cash and cash equivalents	$	178		$	1,287	$	—		$	1,465
Trade accounts receivable, net		10,529			16,252		—			26,781
Other receivables		—			—		—			—
Inventories		10,615			12,233		—			22,848
Current portion of direct financing lease receivable		1,579			—		—			1,579
Prepaid expenses and other current assets		442			2,160		—			2,602

Total Current Assets		23,343			31,932		—			55,275
Property, plant and equipment, net		80,749			40,102		—			120,851
Mineral resources, net		10,563			—		—			10,563
Intangible assets, net		—			1,426		—			1,426
Deferred debt financing, public offering costs and other assets, net		6,843			829		—			7,672

Total Assets	$	121,498		$	74,289	$	—		$	195,787

LIABILITIES AND MEMBERS' EQUITY
Current liabilities
Accounts payable	$	17,293		$	10,248	$	—		$	27,541
Accrued liabilities		3,559			3,719		—			7,278
Deferred revenue		801			—		—			801
Current portion of long-term debt		8,482			839		—			9,321
Current portion of capital lease liability		1,548			—		—			1,548
Current portion of advances from customers		4,043			—		—			4,043

Total Current Liabilities		35,726			14,806		—			50,532
Long-term debt, net of current portion		96,225			33,415		—			129,640
Capital lease liability, net of current portion		5,428			—		—			5,428
Asset retirement obligations		690			—		—			690

Total Liabilities		138,069			48,221		—			186,290
MEMBERS' EQUITY
Previous members' equity (deficit)		(16,571	)		26,068		(9,497	)(a)		—
Predecessor equity		—			—		9,497	(a)		9,497

Total Members' Equity (Deficit)		(16,571	)		26,068		—			9,497

Total Liabilities and Members' Equity	$	121,498		$	74,289	$	—		$	195,787

See accompanying notes to unaudited pro forma condensed combined financial statements.

PREDECESSOR

UNAUDITED PRO FORMA CONDENSED COMBINED BALANCE SHEET

As of December 31, 2011

(in thousands)

	SSS Historical			AEC Historical		Transaction Adjustments			Predecessor Pro Forma

ASSETS
Current assets
Cash and cash equivalents	$	4,580		$	1,941	$	—		$	6,521
Trade accounts receivable, net		2,842			13,452		—			16,294
Other receivables		—			45		—			45
Inventories		2,619			8,478		—			11,097
Prepaid expenses and other current assets		302			751		—			1,053
Asset held for sale		1,338			—					1,338

Total Current Assets		11,681			24,667		—			36,348
Property, plant and equipment, net		36,310			41,136		—			77,446
Mineral resources, net		10,610			—		—			10,610
Intangible assets, net		—			1,742		—			1,742
Deferred debt financing, public offering costs and other assets, net		910			524		—			1,434

Total Assets	$	59,511		$	68,069	$	—		$	127,580

LIABILITIES AND MEMBERS' EQUITY
Current liabilities
Accounts payable	$	6,670		$	8,387	$	—		$	15,057
Accrued liabilities		4,596			1,636		—			6,232
Current portion of long-term debt		377			300		—			677
Current portion of capital lease liability		1,990			—		—			1,990
Current portion of advances from customers		7,968			—		—			7,968

Total Current Liabilities		21,601			10,323		—			31,924
Long-term debt, net of current portion		58,298			32,160		—			90,458
Capital lease liability, net of current portion		6,381			—		—			6,381
Advances from customers, net of current portion		6,165			—		—			6,165
Asset retirement obligations		432			—		—			432

Total Liabilities		92,877			42,483		—			135,360
MEMBERS' EQUITY
Previous members' equity (deficit)		(33,366	)		25,586		7,780	(a)		—
Predecessor equity (deficit)		—			—		(7,780	)(a)		(7,780	)

Total Members' Equity (Deficit)		(33,366	)		25,586		—			(7,780	)

Total Liabilities and Members' Equity	$	59,511		$	68,069	$	—		$	127,580

See accompanying notes to unaudited pro forma condensed combined financial statements.

PREDECESSOR

UNAUDITED PRO FORMA CONDENSED COMBINED BALANCE SHEET

As of December 31, 2010

(in thousands)

	SSS Historical			AEC Historical		Transaction Adjustments			Predecessor Pro Forma

ASSETS
Current assets
Cash and cash equivalents	$	2,002		$	3,262	$	—		$	5,264
Trade accounts receivable, net		1,147			9,616		—			10,763
Other receivables		—			1,602		—			1,602
Inventories		670			4,313		—			4,983
Prepaid expenses and other current assets		44			313		—			357

Total Current Assets		3,863			19,106		—			22,969
Property, plant and equipment, net		19,853			43,113		—			62,966
Mineral resources, net		10,656			—		—			10,656
Intangible assets, net		—			2,140		—			2,140
Deferred debt financing, public offering costs and other assets, net		1,077			506		—			1,583

Total Assets	$	35,449		$	64,865	$	—		$	100,314

LIABILITIES AND PARTNERS EQUITY
Current liabilities
Accounts payable	$	1,645		$	9,470	$	—		$	11,115
Accrued liabilities		3,916			6,603		—			10,519
Current portion of long-term debt		934			6,224		—			7,158
Current portion of capital lease liability		—			120		—			120
Current portion of seller notes and subordinated debt		—			13,052		—			13,052
Derivative contract liability		—			243		—			243

Total Current Liabilities		6,495			35,712		—			42,207
Long-term debt, net of current portion		58,680			25,848		—			84,528
Capital lease liability, net of current portion		—			44		—			44
Asset retirement obligations		48			—		—			48

Total Liabilities		65,223			61,604		—			126,827
MEMBERS' EQUITY
Previous members' equity (deficit)		(29,774	)		3,261		26,513	(a)		—
Predecessor equity (deficit)		—			—		(26,513	)(a)		(26,513	)

Total Members' Equity (Deficit)		(29,774	)		3,261		—			(26,513	)

Total Liabilities and Members' Equity	$	35,449		$	64,865	$	—		$	100,314

See accompanying notes to unaudited pro forma condensed combined financial statements.

PREDECESSOR

UNAUDITED PRO FORMA CONDENSED COMBINED STATEMENT OF OPERATIONS

For the Year Ended December 31, 2012

(in thousands)

	SSS Historical			AEC Historical			Transaction Adjustments		Predecessor Pro Forma

REVENUES
Revenues	$	66,697		$	552,390		$	—	$	619,087
Other revenues		—			5,009			—		5,009

		66,697			557,399			—		624,096

OPERATING EXPENSES
Cost of product		17,638			539,080			—		556,718
Operations and maintenance		9,763			8,923			—		18,686
Depreciation, depletion and amortization		6,377			2,742			—		9,119
Selling, general and administrative expenses		5,512			4,638			—		10,150
Provision for bad debts		57								57
Loss on disposal of equipment		(33	)		5			—		(28	)

		39,314			555,388			—		594,702

Income from operations		27,383			2,011			—		29,394

OTHER EXPENSE (INCOME)
Interest expense		10,619			813			—		11,432
Litigation settlement expense		—			750			—		750
Other		(112	)		(33	)		—		(145	)

		10,507			1,530			—		12,037

Income before taxes		16,876			481			—		17,357
Provision for state margin taxes		81			—			—		81

Net income	$	16,795		$	481		$	—	$	17,276

See accompanying notes to unaudited pro forma condensed combined financial statements.

PREDECESSOR

UNAUDITED PRO FORMA CONDENSED COMBINED STATEMENT OF OPERATIONS

For the Year Ended December 31, 2011

(in thousands)

	SSS Historical			AEC Historical			Transaction Adjustments		Predecessor Pro Forma

REVENUES
Revenues	$	28,179		$	343,734		$	—	$	371,913
Other revenues		—			5,575			—		5,575

		28,179			349,309			—		377,488

OPERATING EXPENSES
Cost of product		14,603			331,416			—		346,019
Operations and maintenance		4,708			8,523			—		13,231
Depreciation, depletion and amortization		4,022			2,858			—		6,880
Selling, general and administrative expenses		4,995			3,973			—		8,968
Impairment of land		762			—					762
Equipment relocation costs		572			—					572
Loss (gain) on disposal of equipment		364			(111	)		—		253

		30,026			346,659			—		376,685

(Loss) income from operations		(1,847	)		2,650			—		803

OTHER EXPENSE (INCOME)
Interest expense		1,835			1,536			—		3,371
Gain on extinguishment of trade payable		—			(1,212	)		—		(1,212	)
Gain from debt restructuring		—			(472	)		—		(472	)
Changes in fair value of interest rate swap		—			(243	)		—		(243	)
Other		42			(99	)		—		(57	)

		1,877			(490	)		—		1,387

Income (loss) before taxes		(3,724	)		3,140			—		(584	)
Provision for state margin taxes		101			—			—		101

Net income (loss)	$	(3,825	)	$	3,140		$	—	$	(685	)

See accompanying notes to unaudited pro forma condensed combined financial statements.

PREDECESSOR

UNAUDITED PRO FORMA CONDENSED COMBINED STATEMENT OF OPERATIONS

For the Year Ended December 31, 2010

(in thousands)

	SSS Historical			AEC Historical			Transaction Adjustments		Predecessor Pro Forma

REVENUES
Revenues	$	17,131		$	239,056		$	—	$	256,187
Other revenues		—			5,420			—		5,420

		17,131			244,476			—		261,607

OPERATING EXPENSES
Cost of product		14,138			231,456			—		245,594
Operations and maintenance		4,073			7,616			—		11,689
Depreciation, depletion and amortization		2,568			3,079			—		5,647
Selling, general and administrative expenses		6,246			3,783			—		10,029
Provision for bad debts		702			330					1,032
Gain on disposal of equipment		—			(180	)		—		(180	)

		27,727			246,084			—		273,811

Loss from operations		(10,596	)		(1,608	)		—		(12,204	)

OTHER EXPENSE (INCOME)
Interest expense		980			3,892			—		4,872
Changes in fair value of interest rate swap		—			(281	)		—		(281	)
Other		—			(49	)		—		(49	)

		980			3,562			—		4,542

Loss before taxes		(11,576	)		(5,170	)		—		(16,746	)
Provision for state margin taxes and (benefit) from income taxes		36			(1,051	)		—		(1,015	)

Net loss	$	(11,612	)	$	(4,119	)	$	—	$	(15,731	)

See accompanying notes to unaudited pro forma condensed combined financial statements.

PREDECESSOR

NOTES TO UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS

The unaudited pro forma condensed combined financial statements have been derived from the historical consolidated financial statements of Superior Silica Holdings LLC ("SSH") and AEC Holdings LLC ("AEC Holdings"), which together comprise our predecessor for accounting purposes (the "Predecessor"), included elsewhere in this prospectus.

SSH and AEC Holdings are under common control of a private equity fund and as a result the historical financial statements of SSH and AEC Holdings are recorded as a combination of entities under common control.

The pro forma adjustments give effect to the acquisition of AEC Holdings by SSH to form the Predecessor.

The pro forma adjustments have been prepared as if the completion of the acquisition of AEC Holdings by SSH had taken place on December 31, 2010 in the case of the unaudited pro forma balance sheets and January 1, 2010 for the unaudited pro forma statements of operations.

All of the assets and liabilities acquired by SSH will be recognized at their historical basis due to the companies currently being under common control. The unaudited pro forma condensed combined statements of operations have been prepared on the basis that we will be treated as a partnership for U.S. federal income tax purposes.

We have audited the accompanying consolidated balance sheets of Superior Silica Holdings LLC (the "Company") as of December 31, 2012, 2011 and 2010 and the related consolidated statements of operations, members' deficit and cash flows for the years then ended. These financial statements are the responsibility of the Company'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 Company 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 Company'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 presentation of the financial statements. 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 Superior Silica Holdings LLC at December 31, 2012, 2011 and 2010, and the results of its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.

December 31,	2012		2011

Assets
Current assets
Cash and cash equivalents	$	177,997	$	4,579,757
Accounts receivable, net		10,528,996		2,841,505
Inventories		10,615,110		2,618,859
Direct financing lease receivable		1,578,776		—
Prepaid expenses and other current assets		442,507		302,208
Asset held for sale		—		1,338,305

Total current assets		23,343,386		11,680,634

Noncurrent assets
Property, plant and equipment, net		80,748,995		36,310,151
Mineral resources, net		10,563,493		10,609,714
Deferred financing costs, net		3,300,036		648,556
Deferred public offering costs		3,280,951		—
Deposits		261,635		261,635

Total noncurrent assets		98,155,110		47,830,056

Total assets	$	121,498,496	$	59,510,690

December 31,	2012			2011

Liabilities and Members' Deficit
Current liabilities
Accounts payable	$	17,033,670		$	6,424,234
Accounts payable—related party		258,863			245,678
Accrued legal fees		99,000			3,585,000
Accrued liabilities		3,349,112			812,485
Accrued liabilities—related party		110,695			198,665
Deferred revenue		801,315			—
Current portion of long-term debt		8,482,367			376,682
Current portion of advances from customers		4,042,961			7,968,473
Current portion of capital lease liability		1,548,074			1,989,686

Total current liabilities		35,726,057			21,600,903

Noncurrent liabilities
Revolving line of credit		8,249,099			—
Long-term debt—related parties		25,036,420			4,676,923
Long-term debt, net of current portion		62,940,554			53,621,009
Advances from customers, net of current portion		—			6,165,297
Capital lease liability, net of current portion		5,427,827			6,381,021
Asset retirement obligations		689,646			431,646

Total noncurrent liabilities		102,343,546			71,275,896

Total liabilities		138,069,603			92,876,799
Commitments and Contingencies (Note 10)
Members' Deficit		(16,571,107	)		(33,366,109	)

Total liabilities and members' deficit	$	121,498,496		$	59,510,690

Years Ended December 31,	2012			2011

Revenues	$	66,696,808		$	28,179,276

Operating Expenses
Cost of sand		17,637,188			14,602,786
Operations and maintenance		9,762,693			4,707,922
Depreciation, depletion and amortization		6,377,196			4,021,731
General, administrative and selling expenses		5,350,311			4,524,250
General and administrative expenses—related parties		161,982			461,069
Impairment of land		—			761,695
Provision for bad debts		56,965			10,539
Equipment relocation costs		—			572,300
(Gain) loss on disposal of property and equipment		(33,000	)		364,163

		39,313,335			30,026,455

Income (loss) from operations		27,383,473			(1,847,179	)
Other (Income) and Expense
Interest expense, net		9,240,488			1,700,351
Interest expense—related parties		1,379,423			134,392
Other (income) expense		(112,440	)		41,927

		10,507,471			1,876,670

Income (loss) before provision for state margin taxes		16,876,002			(3,723,849	)
Provision for state margin taxes		81,000			100,927

Net income (loss)	$	16,795,002		$	(3,824,776	)

Net income (loss) per member unit:
Net income (loss) available to unit holders	$	16,795,002		$	(3,824,776	)
Weighted-average member units outstanding		46,906,166			45,829,556
Basic and diluted	$	0.36		$	(0.08	)

Years Ended December 31,	2012			2011

Cash Flows from Operating Activities
Net income (loss)	$	16,795,002		$	(3,824,776	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		6,377,196			4,021,730
Interest converted to long-term debt		742,520			—
Amortization of deferred financing costs		640,851			212,852
Loss on early extinguishment of long-term debt		377,063			—
Amortization of debt discount		92,304			92,308
Write-off of accounts receivable		56,965			10,539
Accretion of restructured long-term debt		(267,841	)		(367,327	)
(Gain) loss on disposal of property and equipment		(33,000	)		364,163
Impairment of land		—			761,695
Changes in operating assets and liabilities:
Accounts receivable		(17,033,950	)		(3,571,168	)
Inventories		(7,996,251	)		(1,949,267	)
Prepaid expenses and other current assets		34,584			159,877
Accounts payable and accrued liabilities		2,415,280			6,571,444

Net cash provided by operating activities		2,200,723			2,482,070

Cash Flows from Investing Activities
Purchases of property, plant and equipment		(39,061,749	)		(14,243,077	)
Proceeds from disposal of asset held for sale		1,338,305			—
Proceeds from disposal of property and equipment		33,000			331,311

Net cash used in investing activities		(37,690,444	)		(13,911,766	)

Cash Flows from Financing Activities
Proceeds from Term B credit facility		15,804,641			—
Proceeds from related party debt		14,775,000			—
Proceeds from revolving credit facility		6,650,000			—
Payments on revolving credit facility		(2,000,000	)		—
Payments on Term A credit facility		(1,500,000	)		—
Payments on capital lease liability		(1,394,805	)		—
Payments of other long-term debt		(677,642	)		(3,134,605	)
Payments of public offering costs		(353,665	)		—
Payments of deferred financing costs		(215,568	)		—
Proceeds from customer advances		—			16,000,000
Proceeds from other long-term debt		—			1,141,439

Net cash provided by financing activities		31,087,961			14,006,834

(Decrease)/increase in cash and cash equivalents		(4,401,760	)		2,577,138
Cash and cash equivalents at beginning of year		4,579,757			2,002,619

Cash and cash equivalents at end of year	$	177,997		$	4,579,757

Supplemental Disclosure of Cash Flow Information:
Cash paid for:
Interest	$	6,601,700		$	102,194
State margin taxes		67,500			68,092
Non-cash items:
Partial extinguishment of long-term debt paid by lenders		32,300,444			—
Customer advances offset against receivables		10,090,809			1,866,230
Purchases of property, plant and equipment included in accounts payable		9,454,710			—
Equipment purchases financed with notes payable		4,695,359			201,082
Accrued legal fees paid by lenders		3,950,000			—
Deferred public offering costs accrued and not paid		2,786,511			—
Recognition of a direct financing lease receivable		2,700,000			—
Deferred financing costs added to long-term debt balances		2,023,009			—
Deferred financing costs paid by lenders		1,461,380			—
Prepaid insurance financed with notes payable		469,633			270,085
Capitalized reclamation costs		258,000			383,318
Deferred public offering costs paid by lenders		112,275			—
Recognition of a capital lease liability		—			8,370,707
Sale-leaseback of plant and equipment		—			1,123,865
Vendor invoices paid by lenders		—			858,561
Vendor invoice paid by member		—			232,632

Superior Silica Holdings LLC ("SSH") was organized on June 5, 2008 in the State of Texas and began operations on June 20, 2008 upon the acquisition of Texas Sports Sand, Inc. ("TSSI"). SSH and its wholly owned subsidiary Superior Silica Sands LLC (collectively the "Company") produces and sells various grades of sand primarily used in the extraction of oil and natural gas and the production of numerous building products and foundry materials. The Company's original industrial sand processing facility began in Kosse, Texas. During 2011, the Company opened new industrial sand processing facilities in New Auburn, Wisconsin. In December 2012, the Company opened new industrial sand processing facilities in Barron, Wisconsin.

The consolidated financial statements include the accounts of Superior Silica Holdings LLC and its wholly-owned subsidiary, Superior Silica Sands LLC. All intercompany accounts and transactions have been eliminated in consolidation.

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.

The Company's financial instruments consist primarily of cash and cash equivalents, accounts receivable, accounts payable and debt instruments. The carrying amounts of financial instruments, other than the debt instruments, are representative of their fair values due to their short maturities. The Company's long-term debt has stated interest rates ranging from 0% to 18% as of December 31, 2012. The carrying values and fair values of debt instruments that are not carried at fair value in the consolidated balance sheets are as follows:

Financial instruments that potentially subject the Company to concentrations of credit risk are cash and cash equivalents and accounts receivable. All of the Company's cash and cash equivalents were fully insured at December 31, 2012 and 2011 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 2013, insurance coverage will revert to $250,000 per depositor at each financial institution and the Company's cash balances may again exceed federally insured limits. Management believes that its customer acceptance, billing and collection policies are adequate to minimize potential credit risk on accounts receivable. The Company continuously evaluates the credit worthiness of its customers' financial condition and generally does not require collateral.

As of December 31, 2012, four customers had accounts receivable balances of 10% or higher as follows; 39%, 19%, 14%, and 12%. As of December 31, 2011, four customers had total individual trade receivable balances of 10% or higher as follows; 47%, 24%, 13%, and 11%. No other customer balance exceeded 10% of the total trade receivable balance as of December 31, 2012 and 2011. The Company conducts business based on periodic evaluations of its customers' financial condition and generally does not require collateral to secure obligations to the Company. While certain inherent uncertainty exists within the industry and general economy, management does not believe a significant risk of loss exists from a concentration of credit.

For the year ended December 31, 2012, three customers had revenues of 10% or higher as follows: 42%, 28% and 13%. For the year ended December 31, 2011, four customers had total individual revenues of 10% or higher as follows: 31%, 19%, 19%, and 12%. No other customer's revenues exceeded 10% of total sales for the years ended December 31, 2012 and 2011.

During the years ended December 31, 2012 and 2011, purchases from three major suppliers accounted for approximately 52% and 57% of total purchases, respectively. As of December 31, 2012 and 2011, accounts payable to three suppliers were individually greater than 10% of the total accounts payable balance and were approximately 54% and 80% of the total accounts payable balance, respectively. While the Company's raw materials are primarily purchased from two suppliers as of

December 31, 2012, management believes it to be unlikely that any materially adverse unilateral contract modifications would take place which would impact future revenues and gross margins.

The Company recognizes revenue when persuasive evidence of an arrangement exists, delivery of products has occurred, the sales price charged is fixed or determinable, collectability is reasonably assured, and the risk of loss is transferred to the customer. This generally means that the Company recognizes revenue when the sand leaves the Company's plants, including sand shipped through leased rail cars which is also on FOB shipping point terms. The sand is generally transported via railcar or trucking companies hired by the customer.

The Company derives its revenue by mining and processing minerals that its customers purchase for various uses. Its revenues are primarily a function of the price per ton realized and the volumes sold. In some instances, its revenues also include a charge for transportation services it provides to its customers. The Company's transportation revenue fluctuates based on a number of factors, including the volume of product it transports under contract, service agreements with its customers, the mode of transportation utilized and the distance between its plants and customers.

The Company sells a limited amount of its products under short-term price agreements or at prevailing market rates. The majority of the Company's revenues are realized through take-or-pay supply agreements with three oilfield services companies. Initial terms of these contracts expire between 2013 and 2021. These agreements define, among other commitments, the volume of product that its customers must purchase, the volume of product that the Company must provide and the price that the Company will charge and that its customers will pay for each ton of contracted product. 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. As a result, the Company's realized prices may not grow at rates consistent with broader industry pricing. For example, during periods of rapid price growth, its realized prices may grow more slowly than those of competitors, and during periods of price decline, its realized prices may outperform industry averages. With respect to the take-or-pay arrangements, if the customer is not allowed to make up deficiencies, the Company recognizes revenues to the extent of the minimum contracted quantity, assuming payment has been received or is reasonably assured. If deficiencies can be made up, receipts in excess of actual sales are recognized as deferred revenues until production is actually taken or the right to make up deficiencies expires.

The Company invoices the majority of its customers on a per shipment basis, although for some larger customers, the Company consolidates invoices weekly or monthly. Standard terms are net 30 days, although extended terms are offered in competitive situations. The amounts invoiced include the amount charged for the product, transportation costs (if paid by the Company) and costs for additional services as applicable, such as costs related to transload the product from railcars to trucks for delivery to the customer site.

Revenues from sales to customers who have advanced payments to the Company are invoiced to accounts receivable and recognized as revenue at the gross contractual rate per ton. Subsequently, the Company recognizes a reduction of accounts receivable and a corresponding reduction in the "advances from customers" liability (net of accrued interest) for the contracted repayment rate per ton.

Transportation revenue is reported in revenue and is derived from the Company charging its customers i) to deliver product to their locations, ii) to deliver product to a transload site from which customers are able to take possession, or iii) for leased rail cars used to transport product to the customer's location. Transportation expense is the cost the Company pays i) to ship product from its production facilities to customer facilities ii) to a transload site from which customers can take possession, or iii) to a third party for lease of rail cars which are then leased to other customers to transport the product to the customer's location, and it is included in operations and maintenance expense. Less than 2% of the Company's revenues for the years ended December 31, 2012 and 2011 were derived from transportation charges.

At times the Company ships product to customers from suppliers on sand swap agreements. The Company defers any revenue from sand shipped to customers in which the Company has not shipped the corresponding swap sand to the supplier.

The Company considers all highly liquid investments with a maturity of three months or less at the time of purchase to be cash equivalents. All of our non-interest bearing cash balances were fully insured at December 31, 2012 and 2011 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 will revert to $250,000 per depositor at each financial institution, and our non-interest bearing cash balances may again exceed federally insured limits.

Trade accounts receivable are recognized at their invoiced amounts and do not bear interest. The Company maintains an allowance for doubtful accounts for estimated losses resulting from the inability of its customers to make required payments. The Company estimates its allowances based on specifically identified amounts that are believed to be uncollectible. If the financial condition of the Company's customers were to deteriorate, resulting in an impairment of their ability to make payments, additional allowances might be required. After all attempts to collect a receivable have failed, the receivable is written off against the allowance. No allowance for doubtful trade accounts receivable was established at December 31, 2012 and 2011.

Inventory consists of both wet and dried sand stated at lower of cost or market value. Cost is determined using the average cost method. For the years ended December 31, 2012 and 2011, the Company had no write down of inventory as a result of any lower of cost or market assessment. Overhead is capitalized at an average per unit rate based on actual costs incurred. The Company performs periodic physical inventory measurements to verify the quantity of inventory on hand. Due to variation in sand density and moisture content and production processes utilized to manufacture the Company's products, physical inventories will not necessarily detect all variances. To mitigate this risk, the Company recognizes a yield adjustment on its inventories. The Company performed physical inventory measurements on or around December 31, 2012 and 2011.

In July 2012, the Company entered into an agreement with a third party in which the Company built a wet sand processing plant that is being operated by this third party for the purpose of processing wet sand. The Company is paying a specified fee per ton of processed sand during the ten-year term of the agreement and in turn will apply a specified fee per ton of purchased sand as payment by the third party for eventual legal transfer of ownership, at no additional charge, of the plant to the third party. The fee from the third party to the Company will no longer be withheld once the full cost of the plant is withheld by the Company including interest at 6.0% per annum. The initial cost of the plant totaled $2.7 million and was recognized as a direct financing lease receivable in July 2012. The Company anticipates receiving the full value of this receivable during 2013 based on anticipated level of sand purchases; therefore, the remaining balance due as of December 31, 2012 has been classified as a current asset.

In February 2012, the Company sold a parcel of land, which was not a revenue generating asset, resulting in net proceeds of $1,338,305 which was less than the net book value of the asset at the time the decision was made to sell (June 2011). As a result, the Company recognized an impairment loss of $761,695 and adjusted the carrying value of the land to the fair value less cost to sell which amounted to $1,338,305. The land was classified as a current asset as of December 31, 2011.

The Company records 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.

Property under construction is stated at cost. This includes cost of construction, plant and equipment and other direct costs. Property under construction is not depreciated until such time that the relevant assets are completed and put into operational use.

Property, plant and equipment include mine development costs such as engineering, mineralogical studies, drilling and other related costs to develop the mine, the removal of overburden to initially expose the mineral and building access ways. Exploration costs are expensed as incurred and classified as an exploration expense. Capitalization of mine development project costs begins once the deposit is classified as proven and probable reserves. Drilling and related costs are capitalized for deposits where proven and probable reserves exist and the activities are directed at obtaining additional information on the deposit or converting non-reserve minerals to proven and probable reserves and the benefit is to be realized over a period greater than one year.

Interest and other costs incurred in connection with the borrowing of funds are capitalized during the construction of plant and equipment as part of the cost of acquiring assets.

Depreciation and amortization of other property, plant and equipment is provided for, commencing when such assets become operational, on the straight-line basis over the following estimated useful lives.

The Company follows the group method of depreciation for certain large asset acquisitions whereby a single composite depreciation rate is applied to the gross investment in a class of similar assets, despite small differences in the service life or salvage value of individual property units within the same asset class. In accordance with the group method of depreciation, upon sale or retirement of properties in the normal course of business, cost less net salvage value is charged to accumulated depreciation. As a result, no gain or loss is recognized in income under the group method as it is assumed that the assets within the group on average have the same life and characteristics and therefore that gains or losses offset over time. For retirements of depreciable properties that do not occur in the normal course of business, a gain or loss may be recognized if the retirement varies significantly from the retirement pattern identified through depreciation studies. A gain or loss is recognized for the sale of land or disposal of assets not recognized using the group method.

Mineral resources which initially resulted from the 2008 acquisition of the Company are recorded at fair value at the date of acquisition and represented proven and probable sand reserves. Subsequent additions are recorded at cost but no such additions have been capitalized to date since the acquisition of the Company in 2008. The provision for depletion of the cost of mineral resources is computed on the units-of-production method. Under this method, the Company computes the provision by multiplying the total cost of the mineral resources by a rate arrived at by dividing the physical units of sand produced during the period by the total estimated mineral resources at the beginning of the period. Accumulated depletion as of December 31, 2012 and 2011 was $236,507 and $190,286, respectively. Depletion expense for the years ended December 31, 2012 and 2011 amounted to $46,221 and $46,574, respectively.

In accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 360-10-05, long lived assets held and used are reviewed for impairment whenever events or changes in circumstances indicate that the carrying value of an asset may not be recoverable. If circumstances require a long-lived asset be tested for possible impairment, the Company first compares 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.

In management's opinion, there is no impairment of its long-lived assets as of December 31, 2012 and 2011.

Advertising costs, which are included in selling, general and administrative expense, are expensed as incurred and are not material to the consolidated financial statements.

Liabilities for loss contingencies, including environmental remediation costs not within the scope of FASB ASC 410, Accounting for Asset Retirement Obligations, arising from claims, assessments, litigation, fines, and penalties and other sources, are recognized when it is probable that a liability has been incurred and the amount of the assessment and/or remediation can be reasonably estimated. Legal costs incurred in connection with loss contingencies are expensed as incurred. Recoveries of environmental remediation costs from third parties, which are probable of realization, are separately recognized as assets, and are not offset against the related environmental liability. No liabilities for environmental costs were required to be recognized as of December 31, 2012 and 2011.

Deferred financing costs consist of loan financing fees, which are amortized on a method approximating the effective interest method over the term of the loan. The Company wrote off approximately $674,000 of prior deferred financing costs related to the partial extinguishment of debt. See Note 5 for additional discussion.

Debt discounts are amortized on a method approximating the effective interest method over the term of the loan.

The Company's policy is to capitalize interest cost incurred on debt during the construction of major projects. A reconciliation of total interest cost to "Interest Expense" as reported in the Company's consolidated statements of operations is as follows:

The Company follows the provisions of ASC 410-20-05. ASC 410-20-05 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 the Company to recognize an estimated liability for costs associated with the abandonment of its sand mining properties.

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 increased carrying value is depleted using the unit-of-production 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. For the liability recognized, the Company utilized a discounted rate reflecting management's best estimate of its 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.

The Company reported a liability of $689,646 and $431,646 related to this obligation as of December 31, 2012 and 2011, respectively. Changes in the asset retirement obligation are as follows:

In situations where the Company has either invoiced a customer or received payment from a customer, for sand that has not been delivered by the Company, the Company recognizes these amounts as deferred revenue until such time as the Company's obligation has been met.

The Company's transportation and handling costs are included in the operations and maintenance in the consolidated statements of operations.

The Company is treated as a partnership for U.S. federal income tax purposes. Therefore, federal taxable income and any applicable tax credits are included in the federal tax returns of the members, and any federal tax liability relating thereto is borne by the members. The Company is liable for state franchise taxes. State franchise taxes for the years ended December 31, 2012 and 2011 amounted to $81,000 and $100,927, respectively.

In accordance with ASC 740-10-30-7 in the Expenses—Income Taxes topic, the Company recognizes the effect of uncertain tax positions, if any, only if those positions are more likely than not of being realized. Changes in recognition or measurement are reflected in the period in which the change in judgment occurs. It also requires the Company to accrue interest and penalties where there is an underpayment of taxes, based on management's best estimate of the amount ultimately to be paid, in the same period that the interest would begin accruing or the penalties would first be assessed. It is the Company's policy to classify interest and penalties related to the underpayment of income tax as income tax expense.

The Company has one operating and reporting segment consisting of 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. The Company's chief operating decision maker is considered to be the Chief Executive Officer. The chief operating decision maker allocates resources and assesses performance of the business and other activities at the single reporting segment level.

Basic and diluted income (loss) per member unit is presented within the consolidated statements of operations. Basic income (loss) per member unit is computed by dividing the income (loss) attributable to members by the weighted-average number of outstanding member units for the period. Diluted income (loss) per member unit reflects the potential dilution that could occur if securities or other contracts that may require the issuance of member units in the future were converted. Diluted income per member unit is computed by increasing the weighted-average number of outstanding member units to include the additional member units that would be outstanding after conversion and adjusting net income for changes that would result from the conversion. Only those securities or other contracts that result in a reduction in earnings per member unit are included in the calculation. The Company had no potentially dilutive securities in 2012 and 2011.

In May 2011, the FASB issued ASU No. 2011-04 to provide additional guidance related to fair value measurements and disclosures. The guidance, which is incorporated into FASB ASC 820-10, generally provides clarifications to existing fair value measurement and disclosure requirements and also creates or modifies other fair value measurement and disclosure requirements. The Company adopted this guidance, as required, for the first interim or annual period beginning after December 15, 2011 and the adoption of the guidance did not have a material impact on the Company's financial position or results of operations.

December 31,	2012			2011

Plant equipment	$	43,061,415		$	24,215,493
Wet plant under capital lease:
Machinery and equipment under capital lease		8,403,175			8,403,175
Building under capital lease		1,022,000			1,022,000
Land improvements under capital lease		69,397			69,397
Building and land improvements		25,358,114			5,108,449
Industrial vehicles		3,076,698			2,766,455
Land and land improvements		13,150,006			1,878,834
Capitalized reclamation costs		677,012			419,012
Furniture and office equipment		173,797			27,544

		94,991,614			43,910,359
Less accumulated depreciation and amortization of capital lease		(14,885,431	)		(8,554,457	)

		80,106,183			35,355,902
Construction in progress		642,812			954,249

	$	80,748,995		$	36,310,151

Depreciation and amortization expenses for the years ended December 31, 2012 and 2011 were approximately $6,331,000 and $3,975,000, respectively. This includes amortization expense related to assets under capital lease for the years ended December 31, 2012 and 2011 of $1,270,000 and $526,000, respectively.

The Company estimates that approximately $2.7 million will be incurred subsequent to December 31, 2012 to complete the current construction in progress.

During 2011, the Company sold certain plant and equipment to a third party with a net book value of $1,123,865 in a sale-leaseback transaction resulting in a non-cash reduction of the capital lease liability by the same amount. As a result, the gross value of assets under capital lease totaled $9,494,572 while the initial capital lease liability totaled $8,370,707 as of the date the capital lease was recognized, July 31, 2011.

Also during 2011, the Company relocated certain assets to its New Auburn, Wisconsin facility. The costs associated with the equipment relocation, totaling $572,300, were expensed during 2011.

December 31,	2012		2011

Senior secured note—Term A	$	28,500,000	$	—
Senior secured capital expenditure line of credit—Term B		20,000,000		—
Revolving line of credit		8,249,099		—
Second lien loan to a financial and lending partnership		22,235,219		—
Second lien loan to an affiliate of the majority owner		19,932,693		—
Subordinated debt to an affiliate of the majority owner, net of unamortized discount of $230,773 and $323,077 at December 31, 2012 and 2011		5,103,727		4,676,923
Various notes payable to third parties, payable in monthly installments through August 2014.		687,702		270,710
Term loan to a financial and lending partnership, secured by substantially all of the assets of the Company		—		53,601,981
Note payable to former owner, paid January 2012.		—		125,000

		104,708,440		58,674,614
Less current portion		8,482,367		376,682

	$	96,226,073	$	58,297,932

On September 7, 2012, the Company entered into a $60 million credit facility which comprised of a $30 million Term A note, a $20 million capital expenditure line of credit Term B and a $10 million operating revolving line of credit. The Company drew $58,249,099 of this $60 million facility and used i) $32,300,444 to pay down a portion of the prior senior secured credit facility, referred to as the Term loan above with the remaining balance having a second lien as of December 31, 2012, ii) $24,650,000 to purchase plant and equipment and iii) $1,298,655 to pay certain refinancing fees. All facilities accrue interest at LIBOR plus 375 basis points (3.97% as of December 31, 2012) and will mature in September 2016. The operating revolving line of credit is secured by substantially all of the Company's accounts receivable and inventory and the Term A and Term B loans have first lien positions on all remaining assets. The senior secured credit facility requires the Company to maintain certain debt covenants related to leverage, tangible net worth as well as maximum capital expenditure limits. The Company is in compliance with the $60 million credit facility covenants as of December 31, 2012. The Company has not yet done so but is required by the credit agreement to enter into an interest rate swap agreement to mitigate the risk of potential future fluctuations in interest rates within 180 days of the agreement date. The requirement for the Company to enter an interest swap agreement was extended to May 15, 2013.

The remaining $1,750,901 available on the operating revolving line of credit as of December 31, 2012, was drawn on January 2, 2013.

The unpaid portion of the prior senior secured credit facility, discussed above, was refinanced into a $2,050,000 note and a $19,475,000 note with both notes currently at rates of 12% cash interest plus 6% payment-in-kind ("PIK") interest. The Company wrote off approximately $674,000 of deferred financing costs during 2012 related to the partial extinguishment of the prior senior secured facility. Both notes mature on March 31, 2017. The Company is in compliance with all covenants related to the second lien note as of December 31, 2012. This note matures in March 2017.

On July 20, 2012, the Company entered into a $19.0 million term loan facility with a related party to finance its capital expenditures and working capital requirements. The interest rate on the term loan facility is currently at 18% per annum (12% cash and 6% PIK) and will mature on March 31, 2017. In conjunction with the credit facility financing discussed below, the Company incurred a fee of $579,009 on this facility on September 7, 2012. The fee was added to the outstanding balance of the loan on that date. Upon closing this loan facility, $3,950,000 was paid directly by the related party to third-party legal counsel as full payment of certain accrued legal fees as well as $275,000 paid directly to third-parties for deferred financing costs. This note matures in September 2017.

The three notes described above are now in a second lien position on substantially all of the Company's assets. The Company is in compliance with all covenants related to the second lien loan to an affiliate of the majority owner as of December 31, 2012.

The Company also maintains a loan and security agreement with a related party which is subordinated to the senior secured note and the second lien notes. The note carries a redemption amount of $5,334,500, a stated interest rate of 0% and an effective interest rate of 1.1%. The Company incurred a fee of $334,500 related to this note in February 2012 which was added to the outstanding balance of the loan on that date. This note matures in September 2017. The Company is in compliance with all covenants related to the subordinated debt as of December 31, 2012.

During 2012, the Company entered into two additional notes payable to finance its annual insurance premiums and to finance certain equipment purchases totaling $469,633 and $500,000, respectively. The various notes payable carry interest at rates ranging from 2.77% to 7% and mature between May 2013 and August 2014.

As of December 31, 2011 the Company maintained a senior secured term loan due to a financial and lending partnership. In September 2012, the Company restructured this term loan, as noted above, resulting in a new senior secured debt facility with the remaining portion of this 2011 senior secured

term loan becoming a second lien note as of December 31, 2012. See second lien note discussion above for additional detail regarding the new second lien notes.

Prior to 2011, the Company's term loan lender forgave $1.8 million related to this note which was accounted for prospectively as a troubled debt restructuring and the deferred gain has been accreted over the term of the restructured loan as an adjustment to interest expense. In September 2012, approximately $297,000 of this deferred gain was written off on a pro-rata basis with the amount of the term loan that was paid off by the new senior secured facility noted above. The total remaining unaccreted deferred gain as of December 31, 2012 is approximately $321,000.

As of December 31, 2011, the Company was not in compliance with certain budgeting covenants related to the construction of the new Wisconsin facility. In February 2012, the Company received a waiver of all existing covenants as of December 31, 2011 and the Company was in compliance with various affirmative, negative and other financial covenants contained in the loan and security agreement beginning with the first quarter ending March 31, 2012. The financial covenants included minimum EBITDA for specified periods and limiting capital expenditures to certain amounts.

The following table represents the estimated maturities of the Company's long-term debt as of December 31, 2012:

In April 2011, the Company entered into an agreement with a third party to mine and process the Company's mineral resources at its New Auburn location for a specified fee per ton for five years, after which the Company 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.

Estimated minimum future lease payments, based on estimated future production, under capital lease as of December 31, 2012 for each of the next five years, and in aggregate are as follows:

The Company did not incur any contingent rentals for the years ended December 31, 2012 and 2011.

The Company is committed to purchase a minimum annual quantity of the sand, mined and processed by the third party. The estimated minimum purchase commitments under the agreement as of December 31, 2012 for each of the next five years are as follows:

During 2011, the Company entered into agreements with three customers (the "Sand Supply Agreements") which included customer prepayment provisions. The contract date, prepayment amounts, repayment period, contract term, effective interest rates, and remaining balance as of December 31, 2012 of the prepayments included in the Sand Supply Agreements are as follows:

The Company has 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 current and long-term portions of these obligations have been estimated based on future expected purchase quantities or the minimum required purchases, whichever is greater.

The above obligations are secured by letters of credit that were issued by an affiliate of the Company's 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 are 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, 2012, 100% of the outstanding balance is secured by letters of credit.

The Company has two classes of preferred ownership interest, both of which have active member units: Class A-1 and Class A-2 units. Each class differs in voting rights, profit and loss distribution, and liquidation preferences. During 2011, the Company issued an additional 5,239,500 member units of Class A-2, which were deemed to have an estimated fair value of $0 based on conditions that existed as of the issuance date. As of December 31, 2012 and 2011 the outstanding and issued Class A-1 and Class A-2 is 39,166,666 and 7,739,500, respectively. The Class A-2 members are affiliated with the lender of the second lien loan from an affiliate of the majority owner.

During 2011, a member of the Company paid an invoice on behalf of the Company totaling $232,632 for which no additional consideration was given.

Basic net income (loss) per member unit is computed by dividing the income (loss) attributable to members by the weighted average number of member units outstanding for the period.

There were no outstanding options to purchase member units at December 31, 2012 and 2011 that were anti-dilutive.

The Company sponsors a 401(k) plan (the "Plan") for substantially all employees. The plan provides for the Company to match 100% of employee contributions up to the first 4% of each employee's pay. Additionally, the Company may make discretionary contributions as deemed appropriate by management. Contributions to the Plan, by the Company, totaled approximately $59,000 and $0 for the years ended December 31, 2012 and 2011, respectively.

Related party transactions include reimbursements of certain general and administrative and interest expenses incurred by a member on the Company's behalf of approximately $162,000 and $541,000 incurred in 2012 and 2011, respectively. As of December 31, 2012 and 2011, amounts included in trade accounts payable and accrued expense due to a member were approximately $370,000 and $556,000, respectively.

The Company maintains general liability insurance with limits and deductibles that management believes prudent in light of the exposure of the Company to loss and the cost of insurance.

In connection with the direct financing lease receivable in July 2012, the Company entered into a wet sand purchase agreement with this same third party in which the Company is required to purchase a minimum tonnage of wet sand annually. The agreement term is 10 years and ends on September 1, 2022.

Future minimum annual commitments related to this purchase agreement as of December 31, 2012 are as follows:

The Company purchased approximately $4 million and $0 of wet sand from this third party for the years ended December 31, 2012 and 2011, respectively.

In May 2012, the Company entered into a railway shipping agreement with a railway company requiring the Company to ship certain minimum annual tonnage for a term of 10 years. This agreement commenced on January 1, 2013 and ends on December 31, 2022.

Future minimum annual commitments related to this railway shipping agreement as of December 31, 2012 are as follows:

The Company was not required to make any payments to this railway company during the years ended December 31, 2012 and 2011.

During 2011 and 2012, the Company entered into certain surface lease agreements in Wisconsin. The term of the leases are for 25 years with annual rents totaling approximately $60,000. Rent shall increase by 2% annually. The Company also entered into various lease and royalty agreements during 2012 and 2011. The terms of the lease and royalty agreements are for 25 years and the Company shall pay the lessors a royalty for each ton of washed sands. The Company's minimum annual royalty payments are approximately $600,000 related to these royalty agreements.

The Company also entered into certain operating leases for office space and equipment during 2012 and 2011. Future minimum annual commitments related to office space, equipment and land under operating leases at December 31, 2012 are as follows:

Rental expense for operating leases for the years ended December 31, 2012 and 2011 totaled approximately $723,000 and $48,000, respectively.

The Company maintains general liability insurance with limits and deductibles that management believes prudent in light of the exposure of the Company to loss and the cost of the insurance.

The Company is subject to various claims and litigation arising in the ordinary course of business. The outcome of litigation is uncertain and despite management's views of the merits of any litigation or claims, or the reasonableness of the Company's estimates and reserves, the Company's financial statements could nonetheless materially be affected by an adverse judgment. The Company believes it has adequately reserved for contingencies, if any, arising from any legal matters where an outcome was deemed to be probable and the loss amount would be reasonable estimated. As of December 31, 2012 and 2011, there is no accrued loss for such claims and litigation based on management's review of the existing facts and circumstances and based on the advice of counsel. The legal expenses related to claims and litigations are expensed when incurred. For the years ended December 31, 2012 and 2011, the Company incurred legal expenses amounting to approximately $459,000 and $1,500,000, respectively. Legal expenses for the year ended December 31, 2012 are primarily related to contract review and other ordinary course of business legal fees and not litigation related.

In addition, the Company had been involved in an arbitration case brought by a former supplier that was settled by an agreement in October 2010. The supplier has raised issues regarding the settlement but management believes that the settlement will be enforced. In the opinion of management, the final outcome of the above arbitration will not have a material adverse effect on the liquidity, financial position or results of operations of the Company.

The Company underwent an audit by the Internal Revenue Service ("IRS") for the year ended December 31, 2009. The IRS released a notice stating that no changes need to be made to the Company's 2009 federal income tax return.

The Company has a Long Term Compensation Program, in which additional compensation may be paid based on certain events, as defined in certain agreements with an employee and a consultant. As of December 31, 2012 and 2011, there is no amount due under the Long Term Compensation Program.

The Company evaluated subsequent events through the date that the financial statements were issued.

The Company received an advance of $1,750,901 on January 2, 2013 bringing the revolving line of credit balance to the full commitment amount of $10,000,000.

December 31,	2011		2010

Assets
Current assets
Cash and cash equivalents	$	4,579,757	$	2,002,619
Accounts receivable, net		2,841,505		1,147,104
Inventories		2,618,859		669,592
Prepaid expenses and other current assets		302,208		43,667
Asset held for sale		1,338,305		—

Total current assets		11,680,634		3,862,982

Noncurrent assets
Property, plant and equipment, net		36,310,151		19,852,905
Mineral resources, net		10,609,714		10,656,288
Deferred financing costs, net		648,556		951,741
Deposits		261,635		124,835

Total noncurrent assets		47,830,056		31,585,769

Total assets	$	59,510,690	$	35,448,751

December 31,	2011			2010

Liabilities and Members' Deficit
Current liabilities
Accounts payable	$	6,424,234		$	1,543,472
Accounts payable—related party		245,678			101,884
Accrued legal fees		3,585,000			2,730,375
Accrued liabilities		812,485			1,022,810
Accrued liabilities—related party		198,665			162,777
Current portion of long-term debt		376,682			934,149
Current portion of advances from customers		7,968,473			—
Current portion of capital lease liability		1,989,686			—

Total current liabilities		21,600,903			6,495,467

Noncurrent liabilities
Long-term debt—related parties, net of current portion		4,676,923			58,553,921
Long-term debt, net of current portion		53,621,009			125,000
Advances from customers, net of current portion		6,165,297			—
Capital lease liability, net of current portion		6,381,021			—
Asset retirement obligations		431,646			48,328

Total noncurrent liabilities		71,275,896			58,727,249

Total liabilities		92,876,799			65,222,716
Commitments and Contingencies (Note 10)
Members' deficit		(33,366,109	)		(29,773,965	)

Total liabilities and members' deficit	$	59,510,690		$	35,448,751

Years Ended December 31,	2011			2010

Revenues	$	28,179,276		$	17,130,873

Operating Expenses
Cost of sand		14,602,786			14,138,265
Operations and maintenance		4,707,922			4,072,611
Depreciation, depletion and amortization		4,021,731			2,568,426
General, administrative and selling expenses		4,524,250			5,952,237
General and administrative expenses—related parties		461,069			293,892
Impairment of land		761,695			—
Provision for bad debts		10,539			701,772
Equipment relocation costs		572,300			—
Loss on disposal of property, plant and equipment		364,163			—

		30,026,455			27,727,203

Loss from operations		(1,847,179	)		(10,596,330	)
Other Expense
Interest expense		1,700,351			979,518
Interest expense—related parties		134,392			—
Other		41,927			—

		1,876,670			979,518

Loss before provision for state margin taxes		(3,723,849	)		(11,575,848	)
Provision for state margin taxes		100,927			36,385

Net loss	$	(3,824,776	)	$	(11,612,233	)

Net loss per member unit:
Net loss available to unitholders	$	(3,824,776	)	$	(11,612,233	)
Weighted-average member units outstanding		45,829,556			41,682,132
Basic and diluted	$	(0.08	)	$	$(0.28	)

Years Ended December 31,	2011			2010

Cash Flows from Operating Activities
Net loss	$	(3,824,776	)	$	(11,612,233	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		4,021,730			2,568,426
Amortization of deferred financing costs		212,852			193,937
Loss on disposal of property and equipment		364,163			—
Write-off of accounts receivable		10,539			701,772
Impairment of land		761,695			—
Accretion of restructured long-term debt		(367,327	)		(336,716	)
Amortization of debt discount		92,308			166,245
Interest converted to long-term debt		—			1,054,778
Write-down of inventory		—			148,977
Changes in operating assets and liabilities:
Accounts receivable		(3,571,168	)		613,769
Inventories		(1,949,267	)		2,508,510
Prepaid expenses and other current assets		159,877			252,617
Accounts payable and accrued liabilities		6,571,444			2,441,822

Net cash provided by (used in) operating activities		2,482,070			(1,298,096	)

Cash Flows from Investing Activities
Purchases of property, plant and equipment		(14,243,077	)		(1,383,913	)
Proceeds from disposal of property and equipment		331,311			—

Net cash used in investing activities		(13,911,766	)		(1,383,913	)

Cash Flows from Financing Activities
Proceeds from customer advances		16,000,000			—
Proceeds from long-term debt		1,141,439			5,500,000
Payment of long-term debt		(3,134,605	)		(1,109,735	)
Payment of debt financing costs		—			(425,000	)
Proceeds from equity contribution		—			500,000

Net cash provided by financing activities		14,006,834			4,465,265

Increase in cash and cash equivalents		2,577,138			1,783,256
Cash and cash equivalents at beginning of year		2,002,619			219,363

Cash and cash equivalents at end of year	$	4,579,757		$	2,002,619

Supplemental Disclosure of Cash Flow Information:
Cash paid for:
Interest	$	102,194		$	—
State margin taxes	$	68,092		$	—
Non-cash items:
Forgiveness of long-term debt	$	—		$	42,313,465
Capital lease liability	$	8,370,707		$	—
Customer advances offset against receivables	$	1,866,230		$	—
Sale-leaseback of plant and equipment	$	1,123,865		$	—
Interest converted to long-term debt	$	—		$	1,054,778
Capitalized reclamation costs	$	383,318		$	—
Prepaid insurance financed with notes payable	$	270,085		$	—
Vendor invoices paid directly by lenders	$	858,561		$	—
Vendor invoice paid directly by member	$	232,632		$	—
Capitalized interest	$	224,493		$	—
Equipment purchases financed with notes payable	$	201,082		$	—

Superior Silica Holdings LLC ("SSH") was organized on June 5, 2008 in the State of Texas and began operations on June 20, 2008 upon the acquisition of Texas Sports Sand, Inc. ("TSSI"). SSH and its wholly owned subsidiary Superior Silica Sands LLC (collectively the "Company") produces and sells various grades of sand primarily used in the extraction of oil and natural gas and the production of numerous building products and foundry materials. The Company operates industrial sand processing facilities in Kosse, Texas and New Auburn, Wisconsin.

For the years ended December 31, 2011 and 2010, the Company had net losses of $3.8 million and $11.6 million, respectively. Additionally, the Company had negative working capital and a capital deficit as of December 31, 2011 and 2010. During 2011, the Company began processing sand from its New Auburn, Wisconsin location and obtained certain customer contracts resulting in significant profitability during the fourth quarter of 2011. The Company believes that the customer sales agreements, first obtained during 2011, are expected to allow it to achieve profitable operations on an annual basis through 2012 and beyond. These financial statements have been prepared on the going concern basis which assumes the realization of assets and liquidation of liabilities in the normal course of business. Management believes that the profitable operating results from the Company's New Auburn, Wisconsin location as well as new contracts will provide the resources necessary for the ongoing realization of assets and settlement of liabilities in the normal course of business.

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

The Company's financial instruments consist primarily of cash and cash equivalents, accounts receivable, accounts payable and debt instruments. The carrying amounts of financial instruments, other than the debt instruments, are representative of their fair values due to their short maturities. The term loan and subordinated debt has a stated interest rate of 0% as of December 31, 2011 but management believes that the interest rates on these loans are not materially different than current prevailing market rates, and as such, their carrying value approximates fair value.

Financial instruments that potentially subject the Company to concentrations of credit risk are cash and cash equivalents and accounts receivable. All of the Company's cash and cash equivalents were fully insured at December 31, 2011 and 2010 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 2013, insurance coverage will revert to $250,000 per depositor at each financial institution and the Company's cash balances may again exceed federally insured limits. Management believes that its customer acceptance, billing and collection policies are adequate to minimize potential credit risk on accounts receivable. The Company continuously evaluates the credit worthiness of its customers' financial condition and generally does not require collateral.

Customer A represented 47% and 8% of the trade receivable balance as of December 31, 2011 and 2010, respectively. Customer B represented 24% and 48% of the trade receivable balance as of December 31, 2011 and 2010, respectively. Customer C represented 13% and 16% of the trade receivable balance as of December 31, 2011 and 2010, respectively. Customer D represented 11% and 13% of the trade receivable balance as of December 31, 2011 and 2010, respectively. No other customer balance exceeded 10% of the total trade receivable balance as of December 31, 2011 and 2010.

Customer A represented 31% and 11% of revenues for the years ended December 31, 2011 and 2010, respectively. Customer B represented 20% and 10% of revenues for the years ended December 31, 2011 and 2010, respectively. Customer C represented 18% and 5% of revenues for the years ended December 31, 2011 and 2010, respectively. Customer D represented 12% and 0% of revenues for the years ended December 31, 2011 and 2010, respectively. Customer E represented 7% and 58% of revenues for the years ended December 31, 2011 and 2010, respectively. No other customer represented 10% or more of revenues in any of the periods noted above.

During the year ended December 31, 2011, purchases from three major suppliers accounted for approximately 57% of total purchases. Accounts payable relating to these suppliers were approximately 80% of accounts payable at December 31, 2011. During the year ended December 31, 2010, purchases from three major suppliers accounted for approximately 87% of total purchases. Accounts payable relating to these suppliers were approximately 55% of accounts payable at December 31, 2010.

The Company sells a limited amount of its products under short-term price agreements or at prevailing market rates. The majority of the Company's revenues are realized through take-or-pay supply agreements with three oilfield services companies. The terms of these contracts expire in 2014 and 2021, but either we or our customer may 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; this termination may not occur earlier than May 2015. These agreements define, among other commitments, the volume of product that its customers must purchase, the volume of product that the Company must provide and the price that the Company will charge and that its customers will pay for each ton of contracted product. 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. As a result, the Company's realized prices may not grow at rates consistent with broader industry pricing. For example, during periods of rapid price growth, its realized prices may grow more slowly than those of competitors, and during periods of price decline, its realized prices may outperform industry averages. With respect to the take-or-pay arrangements, if the customer is not allowed to make up deficiencies, the Company recognizes revenues to the extent of the minimum contracted quantity, assuming payment has been received or is reasonably assured. If deficiencies can be made up, receipts in excess of actual sales are recognized as deferred revenues until production is actually taken or the right to make up deficiencies expires.

Transportation revenue is reported in revenue and is derived from the Company charging its customers i) to deliver product to their locations, ii) to deliver product to a transload site from which customers are able to take possession, or iii) for leased rail cars used to transport product to the customer's location. Transportation expense is the cost the Company pays i) to ship product from its production facilities to customer facilities ii) to a transload site from which customers can take possession, or iii) to a third party for lease of rail cars which are then leased to other customers to transport the product to the customer's location, and it is included in operations and maintenance expense. Less than 2% of the Company's 2011 and 2010 revenues were derived from transportation charges.

The Company considers all highly liquid investments with a maturity of three months or less at the time of purchase to be cash equivalents. All of our non-interest bearing cash balances were fully insured at December 31, 2011 and December 31, 2010 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 will revert to $250,000 per depositor at each financial institution, and our non-interest bearing cash balances may again exceed federally insured limits.

Inventory consists of both wet and dried sand stated at lower of cost or market value. Cost is determined using the average cost method. For the year ended December 31, 2010, the Company wrote down inventory by approximately $149,000 as a result of the lower of cost or market assessment. Overhead is capitalized at an average per unit rate based on actual costs incurred.

In February 2012, the Company sold a parcel of land, which was not a revenue generating asset, resulting in net proceeds of $1,338,305 which was less than the net book value of the asset at the time the decision was made to sell (June 2011). As a result, the Company recognized an impairment loss of $761,695 and adjusted the carrying value of the land to the fair value which approximated $1,338,305. The land has been classified as a current asset as of December 31, 2011.

Property, plant and equipment include mine development costs such as engineering, mineralogical studies, drilling and other related costs to develop the mine, the removal of overburden to initially expose the mineral and building access ways. Exploration costs are expensed as incurred and classified as an exploration expense. Capitalization of pre-production and mine development costs begins once the reserve deposit is classified as proven and probable and the expected benefit is to be realized over a period greater than one year.

Interest and other costs incurred in connection with the borrowing of funds are capitalized during the construction of plant and equipment as part of the cost of acquiring assets.

Mineral resources which initially resulted from the 2008 acquisition of the Company are recorded at fair value at the date of acquisition and represented proven and probable sand reserves. Subsequent additions are recorded at cost but no such additions have been capitalized to date since the acquisition of the Company in 2008. The provision for depletion of the cost of mineral resources is computed on the units-of-production method. Under this method, the Company computes 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. Accumulated depletion as of December 31, 2011 and 2010 was $190,286 and $143,712, respectively. Depletion expense for the years ended December 31, 2011 and 2010 amounted to $46,574 and $51,442, respectively.

If circumstances require a long-lived asset be tested for possible impairment, the Company first compares 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.

In management's opinion, there is no impairment of its long-lived assets as of December 31, 2011 and 2010.

Advertising costs, which are included in selling, general and administrative expense, are expensed as incurred and are not material to the consolidated financial statements.

Liabilities for environmental remediation costs are recognized when environmental assessments and/or remediation are probable and the amounts can be reasonably estimated. Environmental expenditures that extend the life, increase the capacity, or improve the safety or efficiency of existing assets are capitalized.

Deferred debt financing costs consist of loan financing fees, which are amortized on a method approximating the effective interest method over the term of the loan.

Debt discounts are amortized on a method approximating the effective interest method over the term of the loan.

Company to recognize an estimated liability for costs associated with the abandonment of its sand mining properties.

The Company reported a liability of $431,646 and $48,328 related to this obligation as of December 31, 2011 and 2010, respectively. Changes in the asset retirement obligation are as follows:

The Company's transportation and handling costs are included in the operations and maintenance in the consolidated statement of operations.

The Company is treated as a partnership for U.S. federal income tax purposes. Therefore, federal taxable income and any applicable tax credits are included in the federal tax returns of the members, and any federal tax liability relating thereto is borne by the members. The Company is liable for state franchise taxes. State franchise taxes for the years ended December 31, 2011 and 2010 amounted to $100,927 and $36,385, respectively.

Basic and diluted loss per member unit is presented within the consolidated statements of operations. Basic loss per member unit is computed by dividing the loss attributable to members by the weighted-average number of outstanding member units for the period. If the Company had recognized net income during 2011 and 2010, diluted income per member unit would reflect the potential dilution that could occur if securities or other contracts that may require the issuance of member units in the future were converted. Diluted income per member unit would be computed by increasing the weighted-average number of outstanding member units to include the additional member units that would be outstanding after conversion and adjusting net income for changes that would result from the conversion. Only those securities or other contracts that result in a reduction in earnings per member unit are included in the calculation. Since the Company recognized losses during both 2011 and 2010, any potential issuance of future member units is not included in the computation of diluted net loss per member unit, because to do so would be anti-dilutive.

In May 2011, the FASB issued ASU No. 2011-04 to provide additional guidance related to fair value measurements and disclosures. The guidance, which is incorporated into FASB ASC 820-10, generally provides clarifications to existing fair value measurement and disclosure requirements and also creates or modifies other fair value measurement and disclosure requirements. The Company will adopt this guidance, as required, for the first interim or annual period beginning after December 15, 2011 and the adoption of the guidance is not expected to have a material impact on the Company's financial position or results of operations.

December 31,	2011			2010

Plant equipment	$	24,215,493		$	17,694,374
Wet plant under capital lease:
Machinery and equipment under capital lease		8,403,175			—
Building under capital lease		1,022,000			—
Land improvements under capital lease		69,397			—
Building and land improvements		5,108,449			2,263,293
Industrial vehicles		2,766,455			2,718,117
Land		2,297,846			2,849,148
Furniture and office equipment		27,544			26,444

		43,910,359			25,551,376
Less accumulated depreciation and amortization of capital lease		(8,554,457	)		(5,698,471	)

		35,355,902			19,852,905
Construction in progress		954,249			—

	$	36,310,151		$	19,852,905

Depreciation and amortization expenses for the year ended December 31, 2011 were approximately $3,449,000 and $526,000, respectively. Depreciation and amortization expenses for the year ended December 31, 2010 were approximately $2,517,000 and $0, respectively.

The Company estimates that an additional $240,000 will be incurred subsequent to December 31, 2011 to complete the construction in progress.

Also during 2011, the Company relocated certain assets to its New Auburn, Wisconsin facility. The costs associated with the equipment relocation, totaling $572,300, were expensed during 2011.

December 31,	2011		2010

Term loan to a financial and lending partnership, secured by substantially all of the assets of the Company	$	53,601,981	$	53,969,306
Subordinated debt to an affiliate of the majority owner, net of unamortized discount of $323,077 and $415,385 at December 31, 2011 and 2010		4,676,923		4,584,615
Notes payable to a financial corporation, net of unamortized discount of $81,630 at December 31, 2010, payable in thirty-six equal monthly installments of $65,916, secured by industrial vehicles, maturing in December 2011		—		700,915
Note payable to a financial corporation, payable in thirty-six equal monthly installments of $9,019, secured by equipment		—		108,234
Various notes payable to third parties, payable in monthly installments through September 2012		270,710		—
Notes payable to former owner, due January 2012		125,000		250,000

		58,674,614		59,613,070
Less current portion		376,682		934,149

	$	58,297,932	$	58,678,921

The Company maintains a term loan due to a financial and lending partnership. In January 2010, the Company restructured this term loan due to cash flow problems and financial difficulties. The Company's term loan lender forgave $1.8 million which was accounted for prospectively as a troubled debt restructuring and is being accreted over the term of the restructured term loan as an adjustment to interest expense. The term loan, which is secured by substantially all of the Company's assets, carried an interest rate of 0% as of December 31, 2011 and 2010. The interest rate is subject to increase on a prospective basis based upon the Company achieving certain adjusted earnings before interest, taxes, depreciation and amortization ("EBITDA") milestones, measured on the last day of each month for the twelve-month period ending on such date, as set forth below:

As of December 31, 2011, the Company was not in compliance with certain budgeting covenants related to the construction of its New Auburn, Wisconsin facility. In February 2012, the Company has received a waiver of all existing covenants as of December 31, 2011, however, it must comply with various affirmative, negative and other financial covenants contained in the loan and security agreement beginning with the first quarter ending March 31, 2012. The financial covenants include minimum EBITDA for specified periods and limiting capital expenditures to certain amounts.

The outstanding principal amount of the term loan and certain subordinated debt shall be prepaid by an amount equal to a specified amount of excess cash flow measured at the end of each fiscal quarter commencing with the first quarter ending June 30, 2012. Such prepayment shall be applied as a principal prepayment of the term loan and/or the subordinated debt based on the agreed distribution schedule by the term loan lender and the subordinated debt lender.

Since the specified amount of excess cash flow cannot presently be determined with any amount of specificity, the Company has classified the entire outstanding balance of the term loan and certain Subordinated Debt as non-current in accordance with the fixed contractual repayment terms as of December 31, 2011 and 2010.

In March 2011, the term loan was amended to allow the Company to receive additional proceeds of $333,333 which was subsequently repaid in April 2011.

As previously discussed, due to a prior debt restructuring, as of the December 31, 2011, the outstanding balance of the term loan is $53.6 million which includes an unamortized deferred gain on restructured long-term debt of $1.1 million, which will result in a final principal balance due of $52.5 million on December 31, 2014. See Note 11 for the subsequent amendment of the term loan.

In February 2009, the Company entered into a loan agreement with an affiliate of its majority owner to fund its working capital requirements. The agreement provided a $13.5 million loan and the amendment made in September 2009 provided an additional $3.0 million loan. The loan agreement contained affirmative, negative and various financial covenants under which the Company was obligated. The loan agreement was set to expire in June 2011 and carried an interest rate of 25% per annum.

In January 2010, the Company entered into a release agreement with the affiliate of its majority owner whereby the affiliate of its majority owner forgave all principal and accrued interest amounting to $20.8 million. The related unamortized deferred financing cost of the subordinated debt which amounted to $385,105 was netted against the forgiven subordinated debt and the Company reclassified the net difference amounting to $20.4 million to member's equity due to the extinguishment transaction being conducted by parties under common control.

The Company maintains a loan and security agreement with another affiliate of its majority owner which is subordinated to the term loan noted above and carried an interest rate of 0% as of December 31, 2011 and 2010. Through various restructurings, the agreement provided for a $4.5 million loan with a redemption amount of $5.0 million. The loan agreement contains affirmative, negative and various financial covenants under which the Company is obligated. The loan is due on June 30, 2015.

In March 2011, the term loan was amended to allow the Company to receive additional proceeds of $1,666,667 (partially in cash and partially in direct payments to suppliers) which was subsequently repaid in April 2011.

As of December 31, 2011, the Company was not in compliance with certain covenants of the subordinated debt. In February 2012, the Company has received a waiver of all existing covenants as of December 31, 2011, however, it must comply with various affirmative, negative and other financial covenants contained in the loan and security agreement beginning with the first quarter ending

March 31, 2012. The financial covenants include minimum EBITDA for specified periods and limiting capital expenditures to certain amounts.

The Company acquired certain industrial vehicle and plant equipment through loans payable monthly over three year periods. These notes were repaid during 2011.

During 2011, the Company entered into various short term notes payable to finance its annual insurance premiums and construction of its natural gas pipelines. These notes carry interest at rates ranging from 2.77% to 7% and mature between May 2012 and November 2013. Future principal payments total $251,682 and $19,028 for 2012 and 2013, respectively.

On June 20, 2008, the Company acquired all of the assets of TSSI and certain mineral rights of the former owners of TSSI (collectively, the "Seller"). The purchase price was $87.7 million and was comprised of $54.3 million in cash, $20.0 million unsecured notes payable to the Seller of TSSI ("Seller Notes"), voting membership interests to former owners valued at $9.4 million ("Seller Shares") and direct acquisition costs of $4.0 million.

In January 2010, the Company, its majority owner and the Seller entered into a separation agreement and agreed that the acquisition consideration would be reduced by cancellation of the Seller Notes the and Seller Shares and, concurrently with such reduction to the acquisition consideration the Company would transfer certain trucks with a net book value of approximately $79,000 and pay the Seller $375,000 of which $125,000 was paid in 2010 and $250,000 shall be paid in two equal annual installments of $125,000 commencing in January 2011. Approximately $22.1 million of the Seller Notes were forgiven and reclassified to members' equity as the Seller, at the time of extinguishment, owned 22.5% of the Company, therefore, the extinguishment transaction occurred between related parties.

The following table represents the estimated maturities of the Company's long-term debt as of December 31, 2011:

Estimated minimum future lease payments, based on estimated future production, under capital lease as of December 31, 2011 for each of the next five years, and in aggregate are as follows:

The Company did not incur any contingent rentals for the years ended December 31, 2011 and 2010.

The Company is committed to purchase a minimum annual quantity of sand mine and process by the third party. The estimated minimum purchase commitments under the agreement as of December 31, 2011 for each of the next five years are as follows:

During 2011, the Company entered into agreements with three customers (the "Sand Supply Agreements") which included customer prepayment provisions. The contract date, prepayment

amounts, repayment period, contract term, effective interest rates, and remaining balance as of December 31, 2011 of the prepayments included in the Sand Supply Agreements are as follows:

The Company has two classes of preferred ownership interest, both of which have active member units: Class A-1 and Class A-2 units. Each class differs in voting rights, profit and loss distribution, and liquidation preferences. During 2011, the Company issued an additional 5,239,500 member units of Class A-2, which were deemed to have an estimated fair value of $0 based on conditions that existed as of the issuance date. As of December 31, 2011, the outstanding and issued Class A-1 and Class A-2 is 39,166,666 and 7,739,500, respectively. As of December 31, 2010, the outstanding and issued Class A-1 and Class A-2 is 39,166,666 and 2,500,000, respectively. The Class A-2 members are affiliated with the term loan creditor.

As discussed in Note 5, the Seller Shares were cancelled. The Seller forgave approximately $22.1 million of Seller Notes and certain affiliates of the majority owner also forgave approximately $20.4 million of subordinated debt and the forgiven Seller Notes and subordinated debt were reclassified to members' equity.

During 2011, a member of the Company paid an invoice on behalf of the Company totaling $232,632 for which no additional consideration was given.

Basic net loss per member unit is computed by dividing the loss attributable to members by the weighted average number of member units outstanding for the period.

There were no outstanding options to purchase member units at December 31, 2011 and 2010 that were anti-dilutive.

Related party transactions include reimbursements of certain general and administrative and interest expenses incurred by a member on the Company's behalf of approximately $541,000 and $197,000 incurred in 2011 and 2010, respectively. As of December 31, 2011 and 2010, amounts included in trade accounts payable and accrued expense due to a member were approximately $444,000 and $265,000, respectively.

In March 2011, the Company entered into certain surface lease agreements in Wisconsin. The term of the leases are for 25 years with annual rents totaling approximately $37,000. Rent shall increase by 2% annually. The Company also entered into various lease and royalty agreements during 2011. The terms of the lease and royalty agreements are for 25 years and the Company shall pay the lessors a royalty for each ton of washed sands. The Company's minimum annual royalty payments will total approximately $550,000 related to these royalty agreements.

The Company also entered into certain operating leases for equipment during 2011. Future minimum annual commitments related to equipment and land under operating leases at December 31, 2011 are as follows:

Rental expense for operating leases for the years ended December 31, 2011 and 2010 totaled approximately $48,000 and $0, respectively.

The Company maintains general liability insurance with limits and deductibles that management believes prudent in light of the exposure of the Company to loss and the cost of the insurance.

The Company is subject to various claims and litigation arising in the ordinary course of business. The outcome of litigation is uncertain and despite management's views of the merits of any litigation or claims, or the reasonableness of the Company's estimates and reserves, the Company's financial statements could nonetheless materially be affected by an adverse judgment. The Company believes it has adequately reserve for contingencies, if any, arising from any legal matters where an outcome was deemed to be probable and the loss amount would be reasonable estimated. As of December 31, 2011 and 2010, there is no accrued loss for such claims and litigation based on management's review of the existing facts and circumstances and based on the advice of counsel. The legal expenses related to claims and litigations are expensed when incurred and for the years ended December 31, 2011 and 2010 the Company incurred legal expenses amounting to approximately $1,500,000 and $2,100,000, respectively.

The Company is undergoing an audit by the Internal Revenue Service for the year ended December 31, 2009. As previously discussed, the Company is treated as a partnership for U.S. federal income tax purposes, therefore, any potential federal income tax exposure are expected to be borne by the members.

The Company has a Long Term Compensation Program, in which additional compensation may be paid based on certain events, as defined in certain agreements with an employee and a consultant. As of December 31, 2011 and 2010, there is no amount due under the Long Term Compensation Program.

AEC Holdings LLC and Subsidiaries

Report of Independent Registered Public Accounting Firm

We have audited the accompanying consolidated balance sheets of AEC Holdings LLC and Subsidiaries (the "Company") as of December 31, 2012, 2011 and 2010, and the related consolidated statements of operations, members' equity and cash flows for the years then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of AEC Holdings LLC and Subsidiaries at December 31, 2012, 2011 and 2010, and the results of its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.

December 31,	2012		2011

Current assets
Cash and cash equivalents	$	1,287,421	$	1,941,055
Accounts receivable, net of allowance for doubtful accounts of $120,000 and $7,132		16,252,179		13,497,369
Inventories		12,232,498		8,477,806
Other current assets		2,159,869		750,834

Total current assets		31,931,967		24,667,064
Property, plant and equipment, net of accumulated depreciation and amortization of $10,022,140 and $7,620,709		40,101,798		41,136,171
Intangible assets, net of accumulated amortization of $2,241,601 and $1,925,591		1,426,397		1,742,407
Deferred financing costs, net of accumulated amortization of $646,616 and $475,651		82,888		253,853
Other assets		746,339		269,848

Total assets	$	74,289,389	$	68,069,343

Years Ended December 31,	2012			2011

Fuel revenues	$	552,390,535		$	343,734,426
Other revenues		5,008,614			5,574,693

Total revenues		557,399,149			349,309,119
Operating expenses
Cost of fuel		539,079,484			331,620,669
Operations and maintenance		8,923,024			8,318,658
Selling, general and administrative		4,638,399			3,972,774
Depreciation and amortization		2,741,576			2,858,429
Loss (gain) on disposal of equipment, net		5,131			(111,171	)

Total operating expenses		555,387,614			346,659,359

Operating income		2,011,535			2,649,760
Other income (expense)
Interest expense		(642,172	)		(1,362,165	)
Amortization of deferred financing cost		(170,965	)		(173,607	)
Litigation settlement expense (Note 13)		(750,000	)		—
Gain on extinguishment of payable (Note 9)		—			1,211,807
Gain from debt restructuring, net (Note 10)		—			472,283
Changes in fair value of interest rate swap		—			243,167
Other		32,913			98,594

Total other income (expense)		(1,530,224	)		490,079

Net income	$	481,311		$	3,139,839

Net income per member unit
Net income available to unitholders	$	481,311		$	3,139,839
Weighted-average member units outstanding		100,000			100,000
Earnings per member unit (basic and diluted)	$	4.81		$	31.40

	Membership Interest			Accumulated Deficit			Total

Balance at December 31, 2010	$	25,600,519		$	(22,339,354	)	$	3,261,165
Capital contribution		4,000,000			—			4,000,000
Forgiveness of seller notes and accrued interest payable, net (Note 11)		6,580,194			—			6,580,194
Forgiveness of subordinated notes and accrued interest (Note 12)		6,689,164			—			6,689,164
Forgiveness of long-term debt in exchange for equity (Note 10)		1,515,016			—			1,515,016
Deconsolidation of subsidiary (Note 2)		(13,515,878	)		13,916,892			401,014
Net income		—			3,139,839			3,139,839

Balance at December 31, 2011		30,869,015			(5,282,623	)		25,586,392
Net income		—			481,311			481,311

Balance at December 31, 2012	$	30,869,015		$	(4,801,312	)	$	26,067,703

Years Ended December 31,	2012			2011

Cash Flows from Operating Activities
Net income	$	481,311		$	3,139,839
Adjustments to reconcile net income to net cash used in operating activities:
Depreciation and amortization of property, plant and equipment		2,425,566			2,460,587
Amortization of intangibles		316,010			397,842
Amortization of deferred financing cost		170,965			173,607
Provision for doubtful accounts		112,868			—
Loss (gain) on disposal of equipment		5,131			(111,171	)
Interest rolled into debt balances		—			759,360
Gain on extinguishment of trade payable (Note 9)		—			(1,211,807	)
Gain on debt restructuring (Note 10)		—			(472,283	)
Change in fair value of derivative financial instrument		—			(243,167	)
Changes in operating assets and liabilities:
Accounts receivable		(2,781,376	)		(3,836,583	)
Inventories		(3,754,692	)		(4,164,446	)
Other current assets and other assets		(1,897,422	)		(489,065	)
Accounts payable and accrued expenses		3,943,438			(3,416,091	)
Tax refund receivable and income taxes payable		(86,457	)		925,388

Net cash used in operating activities		(1,064,658	)		(6,087,990	)

Cash Flows from Investing Activities
Proceeds from disposal of equipment		6,500			91,000
Collections of notes receivable		12,051			1,786
Purchases of property, plant and equipment		(1,402,824	)		(935,215	)

Net cash used in investing activities		(1,384,273	)		(842,429	)

Cash Flows from Financing Activities
Equity contribution		—			4,000,000
Cash distributed to deconsolidated subsidiary (Note 2)		—			(251,442	)
Payment made to a member		—			(125,000	)
Proceeds from equipment loan		709,532			—
Repayment of equipment loan		(205,844	)		(163,576	)
Payment of financing costs		—			(306,364	)
Repayment of long-term debt		(1,208,391	)		(894,243	)
Proceeds from revolver loan		49,500,000			22,100,000
Repayment of revolver loan		(47,000,000	)		(18,749,703	)

Net cash provided by financing activities		1,795,297			5,609,672

Decrease in cash and cash equivalents		(653,634	)		(1,320,747	)
Cash and cash equivalents, beginning of year		1,941,055			3,261,802

Cash and cash equivalents, end of year	$	1,287,421		$	1,941,055

The consolidated financial statements include the accounts of AEC Holdings LLC and the consolidated accounts of all of its wholly owned subsidiaries: Allied Energy Company LLC ("AEC"), Allied Renewable Energy LLC ("ARE"), and W.C. Rice Oil Co., Inc. ("WCRO") (collectively the "Company"). As disclosed in Note 2, on September 29, 2011, WCRO was deconsolidated.

The Company operates a motor fuel bulk storage facility located in Birmingham, Alabama. The Company purchases, blends, markets, and transports light petroleum products to its customers in the Birmingham area. The Company operates a transportation mixture ("transmix") distillation tower that extracts gasoline and diesel fuel from commingled motor fuels. Through AEC, the Company offers terminal cleaning and petroleum reclamation services. The Company also operates a biodiesel refinery that produces renewable fuel from soy oil, animal fats, and waste cooking oil for use in blending with traditional diesel products.

The accompanying consolidated financial statements are the responsibility of the Company's management. The Company eliminates all significant intercompany balances and transactions in the consolidation.

On September 29, 2011, the Company deconsolidated its wholly owned subsidiary WCRO. Pursuant to the Stock Purchase Agreement between the Company and WCRO's new parent, W. C. Rice Oil Holdings LLC ("WCROH"), the Company distributed 100% of the common stock in WCROH for consideration of one dollar ($1.00). In accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 810 Consolidation, when a parent sells or otherwise ceases to own all or part of its ownership interest in its subsidiary, and as a result, the parent no longer has a controlling interest in the subsidiary, deconsolidation of that subsidiary is generally required.

The related party transaction was substantively a pro rata distribution of WCRO common stock to the Company's owners. Management therefore deconsolidated WCRO from the Company's balance sheet effective September 29, 2011 and eliminated the results of WCRO's operations from its consolidated accounts beginning on that date. For periods prior to September 29, 2011, the Company included WCRO's results of operations and balance sheet values in its consolidated accounts. After deconsolidation, the Company has no continuing financial interest in WCRO.

Prior to deconsolidation, WCRO conducted marketing efforts to sell and distribute gasoline and diesel products to wholesale, industrial, and commercial accounts. The Company transferred all of these activities to AEC prior to deconsolidation. In addition, WCRO sold substantially all of its tangible, long-lived assets to AEC for an amount that approximates net book value at the date of transfer. These tangible, long-lived assets consisted of trucks, office equipment and leasehold improvements. Since AEC continues to conduct these business activities, the deconsolidation of WCRO is not a "discontinued operation" in the context of current accounting standards.

At the date of deconsolidation, the net deficit of WCRO consisted of the following:

At the date of deconsolidation, the net deficit distributed to WCROH was valued at an amount that approximates fair value. Receivables and other current assets were based on management's assessment of net realizable value. Cash, land and liabilities were stated at carrying amount which approximates fair value.

On September 29, 2011, the Company entered into a management services contract with WCRO to handle routine transition affairs together with post-deconsolidation administrative matters including but not limited to bookkeeping, sales tax returns, business license filings and ad valorem filings. WCRO compensates the Company for these services at a rate of $100 per hour. In its sole discretion, WCRO has the right to terminate the agreement at any time. For the years ended December 31, 2012 and 2011, the Company had not provided meaningful services under the agreement. Consequently, the Company had not billed WCRO any fees under the agreement. At December 31, 2012 and 2011, the Company did not reflect any amounts due to or due from WCRO or WCROH.

The Company treated the transaction as a distribution to its owners. The Company reduced its members' interest to the extent of the capital contributions to WCRO and decreased its accumulated deficit by the cumulative WCRO losses amounting to approximately $13,516,000 and $13,917,000, respectively. The Company did not report a gain or loss from the deconsolidation. The Company recorded the net deficit of WCRO amounting to the $401,014 in Members' Equity.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America ("GAAP") requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. The accounting estimates that require the most significant, difficult and subjective judgment include:

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. Accounting guidance also establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three broad levels. Level 1 inputs are unadjusted quoted prices in active markets for identical assets or liabilities. Level 2 inputs are inputs other than quoted prices included with Level 1 that are directly or indirectly observable for the asset or liability. Level 3 inputs are inputs that are not observable in the market.

The Company's financial instruments consist primarily of cash and cash equivalents, accounts receivable, accounts payable, debt instruments, and derivative financial instruments. The carrying amounts of financial instruments, other than the debt instruments and derivative financial instruments, are representative of their fair values due to their short maturities. Refer to Note 16 for the fair value of the Company's long term debt instruments and derivative financial instruments.

Financial instruments that potentially subject the Company to concentration of credit risk are cash and cash equivalents and trade accounts receivable. All of the Company's cash and cash equivalents were fully insured at December 31, 2012 and 2011 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 will revert to $250,000 per depositor at each financial institution and the Company's cash balances may again exceed federally insured limits. The Company maintains its cash and cash equivalents in financial institutions it considers to be of high credit quality.

The Company provides credit, in the normal course of business, to customers located throughout the Southeastern United States. The Company performs ongoing credit evaluations of its customers, generally does not require collateral and evaluates the potential credit losses regularly, which when realized, have been within the range of management's expectations.

During the year ended December 31, 2012, one customer accounted for 16% of total revenue. No other customers accounted for more than 10% of total revenue. Revenues from the top 10% of customers accounted for approximately 86% of total revenues. Accounts receivable outstanding relating to these customers was approximately 85% of total accounts receivable at December 31, 2012.

During the year ended December 31, 2011, one customer accounted for 11% of total revenue. No other customers accounted for more than 10% of total revenue. Revenues from the top 10% of customers accounted for approximately 85% of total revenues. Accounts receivable outstanding relating to these customers was approximately 85% of total accounts receivable at December 31, 2011.

During the year ended December 31, 2012, purchases from one major supplier accounted for approximately 69% of total purchases. Accounts payable outstanding relating to this major supplier was approximately 47% of total accounts payable at December 31, 2012.

During the year ended December 31, 2011, purchases from two major suppliers accounted for approximately 58% and 18% of total purchases, respectively. Accounts payable outstanding relating to these two major suppliers were approximately 46% and 0% of total accounts payable at December 31, 2011, respectively.

The Company considers all highly liquid investments with original maturities when purchased of three months or less to be cash equivalents.

Accounts receivable are comprised primarily of amounts owed to the Company through its motor fuel deliveries and are presented net of an allowance for doubtful accounts. The majority of trade receivables are due 10 days from the invoice date. The Company maintains allowances for estimated losses resulting from the inability of its customers to make required payments. The Company estimates its allowances based on specifically identified amounts that are believed to be uncollectible, which are determined based on historical experience and management's assessment of the general financial conditions affecting the Company's customer base. If the financial condition of the Company's customers were to deteriorate, resulting in an impairment of their ability to make payments, additional allowances might be required. After all attempts to collect a receivable have failed, the receivable is written off against the allowance.

Finished goods inventories consist of refined motor fuel products. Motor fuel inventories are stated at the lower of cost or market using the average cost method. Raw materials inventories consist of transmix feedstock. Raw materials inventories are stated at the lower of cost or market using the average cost method.

The Company does not have long-term contracts with any suppliers of petroleum products covering more than 10% of its motor fuel supply. Unanticipated national or international events could result in a curtailment of motor fuel supplies to the Company, thereby adversely affecting motor fuel sales.

Property, plant, and equipment are reported generally at cost. In those instances where property, plant, and equipment become impaired, the Company reports the assets at fair value. Depreciation and amortization are determined primarily under the straight-line method that is based on estimated asset service life taking into account obsolescence.

The Company's policy is to capitalize interest cost incurred on debt during the construction of major projects. For the years ended December 31, 2012 and 2011, the Company did not capitalize any interest costs.

Intangible assets consist of trade names and customer relationships. Trade names are amortized on a straight line basis over 10 years, and customer relationships are amortized using the economic benefits method over 15 years.

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 purchased 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, the Company first compares 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. In management's opinion, no impairment of long-lived assets exists at December 31, 2012 and 2011.

In its review of long-lived assets for possible impairments, the Company made significant estimates and assumptions about future events and changes in circumstances for its biodiesel refinery. At December 31, 2012 and 2011, the carrying value of the Company's biodiesel refinery, net of accumulated depreciation, amounted to approximately $6,647,000 and $6,289,000, respectively. Due to operating economics, the biodiesel refinery had been dormant for approximately four years. In February 2012, the Company commenced actions to recommission and restart the biodiesel refinery. In December 2012, the Company restarted the biodiesel refinery.

WCRO files a separate U.S. federal income tax return in the United States. Accordingly, until its deconsolidation on September 29, 2011, income taxes for this subsidiary are accounted for using the asset and liability method pursuant to FASB ASC 740-10-05, Accounting for Income Taxes. Deferred taxes are recognized for the tax consequences of "temporary differences" by applying enacted statutory tax rates applicable to future years to differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities. The effect on deferred taxes for a change in tax rates is recognized in income in the period that includes the enactment date. The Company recognizes future tax benefits to the extent that realization of such benefits is more likely than not.

The Company and its other wholly owned subsidiaries are treated as a partnership for U.S. federal income tax purposes. Therefore, federal taxable income and any applicable tax credits are included in the federal tax returns of the members, and any federal tax liability relating thereto is borne by the members. The Company is also liable for state and local income and franchise taxes.

In accordance with FASB ASC 740-10-30-7, the Company recognizes the effect of uncertain tax positions, if any, only if those positions are more likely than not of being realized. Changes in recognition or measurement are reflected in the period in which the change in judgment occurs. It also requires the Company to accrue interest and penalties where there is an underpayment of taxes, based on management's best estimate of the amount ultimately to be paid, in the same period that the interest would begin accruing or the penalties would first be assessed. It is the Company's policy to classify interest and penalties related to the underpayment of income tax as income tax expense.

The Company recognizes revenue related to terminal and reclamation 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 the Company's 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.

Basic net income per member unit excludes dilution and is computed using the weighted-average number of member units outstanding. Diluted net income per member unit reflects the potential dilution that could occur if securities or other contracts to issue member units were exercised or converted into member units or resulted in the issuance of member units that then shared in the earnings. The Company has no potentially dilutive securities or contracts outstanding.

Deferred public offering costs that are directly and incrementally associated with professional fees related to a potential public offering are deferred and will be charged against the proceeds of the offering.

Liabilities for environmental remediation costs are recorded when environmental assessment and/or remediation are probable and the amounts can be reasonably estimated. Environmental expenditures that extend the life, increase the capacity, or improve the safety or efficiency of existing assets are capitalized.

The Company reports federal excise tax on motor fuels on a gross basis. Federal and state excise taxes included in revenue and cost of fuel is approximately $37,849,000 and $19,619,000 for the years ended December 31, 2012 and 2011, respectively.

Advertising costs, which are included in selling, general and administrative expense, are expensed as incurred and are not material to the consolidated financial statements.

Deferred financing costs that are directly and incrementally associated with new borrowings are capitalized and are amortized on a method approximating the effective interest method.

The Company accounts for derivatives and hedging activities in accordance with FASB ASC 815-10-05, Accounting for Derivative Instruments and Certain Hedging Activities, 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. The Company's policy is to not hold or issue derivative instruments for trading or speculative purposes. Additional disclosures for derivative instruments are presented in Note 16.

The Company organizes its business into three reportable segments, Fuel Processing and Distribution (FP&D), Services and Corporate. The reportable segments are consistent with how management views the markets served by the Company and the financial information reviewed by the Chief Operating Decision Maker ("CODM"). The Company manages its FP&D and Services segments as components of an enterprise for which separate information is available and is evaluated regularly by the CODM in deciding how to allocate resources and assess performance.

Certain reclassifications have been made to the prior year to conform to current year financial statement presentation.

In May 2011, the FASB issued FASB ASU 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS ("ASU"), an amendment to FASB ASC Topic 820, Fair Value Measurement. The update revises the application of the valuation premise of highest and best use of an asset, the application of premiums and discounts for fair value determination, as well as the required disclosures for transfers between Level 1 and Level 2 fair value measures and the highest and best use of nonfinancial assets. The update provides additional disclosure requirements regarding Level 3 fair value measurements and clarifies certain other existing disclosure requirements. The ASU became effective for the Company for annual periods beginning after December 15, 2011. The Company adopted this standard as required by the ASU.

Changes in the Company's allowance for doubtful accounts for the years ended December 31 are as follows:

The Company estimates that additional $200,000 will be incurred subsequent to December 31, 2012 to complete the construction in progress.

Amortization expense for the years ended December 31, 2012 and 2011 was $316,010 and $397,842, respectively. The annual estimated amortization expense related to these intangibles for each of the five succeeding fiscal years is $288,000, $253,000, $204,000, $164,000, and $133,000.

On April 4, 2011, the Company agreed to satisfy fully a trade payable for an amount less than its carrying amount of $2,851,807. The Company entered into a settlement agreement with a third party product supplier which provides mutual release of all parties and dismissed arbitral and court proceedings. Pursuant to the agreement, the Company paid the product supplier $1,550,000 in cash and transferred real estate with a book value of $90,000 (which approximates fair value). For the year ended December 31, 2011, the Company recognized a gain from the extinguishment of this trade payable amounting to approximately $1,212,000.

At December 31, 2012 and 2011, the Company had a secured credit agreement ("Credit Agreement") with the senior lender that consisted of a revolver loan and term loan, both collateralized

by substantially all of the Company's assets. The Credit Agreement contains affirmative, negative and various financial covenants under which the Company is obligated.

On April 1, 2011, the Company entered into an amendment to the Credit Agreement ("Amended Credit Agreement") with the senior lenders which waived the events of defaults and rescinded the acceleration notice. The Amended Credit Agreement includes the following provisions a) requires the cancellation or forgiveness of all seller notes and all subordinated debt and accrued interest payable and conversion of these debts into equity, b) requires the members contribute $4,000,000 to the Company, c) requires the issuance of equity interests to the senior lenders to the extent of 10% of the issued and outstanding interests of the Company, d) requires the payment of mandatory minimum principal payments on a quarterly basis beginning March 31, 2011 and continuing quarterly thereafter until December 31, 2014, e) modification of the financial covenants and a term loan prepayment arrangement whereby the Company is 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. Excess cash flow is defined generally as earnings before interest, taxes, depreciation, and amortization as reduced for certain capital expenditures, interest on bank debt, tax payments, changes in working capital, and other customary modifications. The senior lenders also forgave $6,014,369 of principal, accrued interest and late fees associated with the term loan and $376,429 of accrued interest attributable to the revolver. The Amended Credit Agreement did not modify the carrying value of the revolver loan principal balance and reinstated the revolver loan commitment to the extent of $15,000,000. The Company accounted for the above debt restructuring as a troubled debt restructuring and recorded the gain or loss on the debt restructuring based on troubled debt restructuring accounting.

Generally, a restructuring of debt constitutes a troubled debt restructuring for accounting purposes if the creditor for economic or other reasons related to the debtor's financial difficulties grants a concession to the debtor that it would not otherwise consider. Pursuant to FASB ASC 470-60, the amendment to the Credit Agreement has been accounted for as a troubled debt restructuring due to the concessions granted by the senior lenders. As a result, unamortized balances of deferred financing fees ($87,000), the fair value of the 10% equity grant to senior lenders ($1,515,000) and the direct cost associated with the debt restructuring ($307,000) were netted against the sum of the carrying value of the term loan ($23,559,000) and accrued interest payable ($1,676,000) at the date of modification. This results in a new carrying amount of approximately $23,326,000. The difference between this new carrying amount of the term loan and the sum of the restructured liability of $18,848,000 and the estimated future interest of the restructured loan amounting to $4,005,000 using an interest rate of 5.5% was recorded as a gain on debt restructuring for the year ended December 31, 2011 amounting to $472,283.

The carrying value of the term loan under the Amended Credit Agreement at December 31, 2012 was $20,751,153 and does not equate to the total future principal cash payments of $18,398,412 due under the term debt as a result of accounting for a troubled debt restructuring. The difference between the carrying value of the term loan and the restructured liability will be recognized by the Company as reduced interest costs over the term of the Amended Credit Agreement. Interest payments to the term loan over the term of the Amended Credit Agreement will be applied to the carrying value of the term loan.

The following table reconciles senior lender records to the Company's modified carrying value of its term loan.

	Term loan per Senior Lender			Reconciling Items			Carrying Value of Term Debt

Term loan principal balance at December 31, 2010	$	23,558,545		$	—		$	23,558,545
Add accrued interest—Term Loan		959,289			—			959,289
Add accrued interest—Revolver		—			282,846			282,846

Balance at December 31, 2010		24,517,834			282,846			24,800,680
Accrued interest—Term loan for period January 1, 2011 through April 1, 2011		323,531			(3,555	)		319,976
Accrued interest—Revolver for period January 1, 2011 through April 1, 2011		—			92,555			92,555
Accrued late fees		21,415			—			21,415

		24,862,780			371,846			25,234,626
Forgiveness of Term loan principal		(4,710,133	)		4,710,133			—
Forgiveness of Term loan accrued interest		(1,282,820	)		1,282,820			—
Forgiveness of late fees		(21,415	)		21,415			—

		18,848,412			6,386,214			25,234,626
Fair value of 10% equity grant to senior lenders		—			(1,515,016	)		(1,515,016	)
Gain from troubled debt restructuring at April 1, 2011, before direct cost incurred in the debt restructuring and write-off of deferred financing cost amounting to $393,540		—			(865,823	)		(865,823	)

Modified carrying value at April 1, 2011		18,848,412			4,005,375			22,853,787
Principal payments		(150,000	)		—			(150,000	)
Interest payments applied to reduce modified carrying value pursuant to FASB ASC 470-60-35-6		—			(744,243	)		(744,243	)

Term loan principal balance at December 31, 2011		18,698,412			3,261,132			21,959,544
Principal payments		(300,000	)		—			(300,000	)
Interest payments applied to reduce modified carrying value pursuant to FASB ASC 470-60-35-6		—			(908,391	)		(908,391	)

Term loan principal balance at December 31, 2012	$	18,398,412		$	2,352,741		$	20,751,153

The reconciling items above are primarily due to the accounting for the troubled debt restructuring for the term loan.

The maturity date of the revolver loan and term loan is April 1, 2015. As of December 31, 2012, the Company is in compliance with the financial covenants of the Amended Credit Agreement. The amount available under the revolver loan at December 31, 2012 and 2011 was $2,000,000 and $4,500,000, respectively. The revolver loan and term loan accrues 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 London interbank offered rates (LIBOR) plus applicable margin which is tied to the Company's financial performance. The Company has the option to elect the type of interest when funds are advanced or to move tranches of the debt between the two types of interest. At

December 31, 2012, the Company elected the LIBOR option for $5,000,000 of its revolver and $18,000,000 of the term loan. The LIBOR option for the revolver loan and term loan is from December 31, 2012 to January 31, 2013. The remaining portions for both revolver loan and term loan were included under the bank's base commercial lending rate plus applicable margin.

The following tables illustrate those portions subject to the base commercial lending rate and the LIBOR rate at December 31, 2012 and 2011.

The following table represents the estimated maturities of the Company's long-term debt:

The Company does not owe a 2013 contingent payment according to the excess cash flow provisions based on results of operations for the year ended December 31, 2012.

The Company borrowed $709,532, which is secured by a first priority security interest in a vapor recovery unit that was constructed and installed by the Company. The borrowing occurred on February 6, 2012. Simultaneous with funding, the Company posted a security deposit to the extent of $70,000. The loan requires thirty-five monthly payments of $23,185. The lender will return the security deposit after the final payment. The loan bears an effective interest rate of 9.2%.

On April 1, 2011, the Seller forgave the seller notes amounting to $6,040,418 and accrued interest payable amounting to $664,776. This forgiveness of the seller notes, net of payment made to one of the sellers amounting to $125,000, was treated as a capital transaction and the amounts were reclassified to members' equity.

On April 1, 2011, the related party forgave the subordinated debt amounting to $6,060,000 and accrued interest payable amounting to $629,164. This forgiveness of the subordinated debt was treated as a capital contribution and the amounts were reclassified to members' equity.

The Company maintains general liability insurance with limits and deductibles that management believes prudent in light of the exposure of the Company to loss and the cost of the insurance.

The Company is presently under examination by the Internal Revenue Service ("IRS") for tax years 2008 and 2009. The examination remains in progress. The IRS has not submitted findings or notice of examination changes. Management believes that the findings, if any, will not have a material effect in the financial position or results of operations of the Company.

In 2012, the Company received an IRS penalty totaling $340,000 due to failure to file terminal operator reports in electronic format. The Company filed these returns in paper format. Management is protesting the audit findings through IRS appeal channels. Management placed the IRS on notice that the Company plans to claim exception from penalty due to reasonable cause. In the opinion of management, the outcome of such matters will not have a material effect on the liquidity, financial position or results of operations of the Company.

The Alabama Department of Revenue ("ADOR") audited Company returns for tax years 2008, 2009, 2010, and 2011. In May 2012, ADOR completed its examination and the Company settled the assessment for approximately $1,000.

In December 2012, the Company settled litigation that alleged environmental damage to property located contiguous to its bulk fuel terminal facility. The settlement agreement extinguished all liabilities, if any, and it included mutual releases between the parties. The Company paid $750,000 to settle this litigation.

The Company is subject to various claims arising in the ordinary course of business. In the opinion of management, the outcome of such matters will not have a material effect on the liquidity, financial position or results of operations of the Company.

The Company has operating leases involving real estate. These leases are noncancellable and expire on various dates through 2013. The expense incurred on operating leases for the years ended December 31, 2012 and 2011 was approximately $200,000 and $271,000, respectively.

At December 31, 2012, future minimum rental payments required under non-cancellable operating leases with terms in excess of one year are as follows:

The Company deconsolidated WCRO on September 29, 2011 and WCRO's taxable income through September 29, 2011 is included in the Company's reported results. WCRO reported revenue, costs, and other tax attributes as a "C-corporation" for federal and state filing purposes. Separately, the Company reports revenue, costs, and other tax attributes as a partnership "pass-through" entity. For the year ended December 31, 2011, WCRO federal taxable income is $0. As of December 31, 2011, WCRO had sufficient net federal tax loss carryforwards to offset any federal taxable income. As a result, the Company recorded no income tax expense for the year ended December 31, 2011. Due to the deconsolidation of WCRO that became effective on September 29, 2011, the Company will not benefit from these tax loss carryforwards. The accompanying statements do not reflect any income tax benefit or liability related to the operations of WCRO at December 31, 2012 and 2011.

The Company adopted FASB ASC 820, which defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. FASB ASC 820 applies to other accounting pronouncements that require or permit fair value measurements; however, it does not require any new 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.

The Company's 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 input that is significant to the fair value measurement.

The Company periodically enters into interest rate swaps and futures contracts in accordance with its risk management strategy to manage the risk associated with changing interest rates and fuel prices. The Company does not designate these instruments as hedging instruments, but accounts for them on a mark to market basis with the changes in the fair value reflected in current earnings. The Company does not use derivative financial instruments for trading or speculative purposes.

An interest rate swap was entered into on July 21, 2008 to manage interest risk associated with the Company's fixed rate borrowings. The maturity date of the swap was August 1, 2011. As of December 31, 2012 and 2011, the Company did not have any outstanding interest rate swaps. For the years ended December 31, 2012 and 2011, the Company recorded realized gains of $0 and $243,167, respectively from its interest rate swap. At December 31, 2012 and 2011, the Company did not have outstanding interest rate swaps.

As of December 31, 2012 and 2011, the Company had 188 and 0 open contracts to manage fuel price risk, respectively. For the year ended December 31, 2012, the realized losses from fuel-related futures amounted to $1,365,206 and unrealized losses amounted to $18,135. For the year ended December 31, 2011, the realized losses from fuel-related futures amounted to $611,452 and unrealized losses amounted to $0. These amounts are reported in cost of fuel in the consolidated Statement of Operations.

The following table provides the assets and liabilities carried at fair value measured on a recurring basis:

As discussed at Note 10, the Company granted the senior lenders a 10% equity interest in the Company during 2011. The Company determined the fair value of the 10% senior lender equity grant using Level 3 inputs. Level 3 inputs are unobservable in that there is little or no market data. The Company developed its own assumptions to assess the fair value of the equity grant. Generally, the assumptions included a compilation of comparable earnings data (from publicly available sources) for companies similarly situated to the Company. From this information, the Company developed an earnings multiple pattern and computed a discounted cash flow analysis ("DCF") using reasonable estimates for future earnings. The Company used the DCF analysis to determine an indicated enterprise value, net of estimated debt. The Company multiplied the indicated enterprise value by 10% and further reduced this amount by applying a non-controlling interest discount. The Company derived $1,515,016 as the fair value for the 10% equity grant to its senior lenders.

The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy:

As of December 31, 2012 and 2011, the fair values of the Company's long-term debt and revolver as a follows:

The fair value measurements for long-term debt including current maturities of long-term debt are based on estimates from existing creditor relationships (Level 3 inputs).

On January 1, 2009, the Company initiated a 401(k) savings plan for all full time employees who have completed three months of service. Matching contributions will be a discretionary percentage, determined by the Company. During 2012 and 2011, the Company recorded compensation expense of approximately $166,000 and $155,000, respectively, related to the discretionary contributions that have been recorded in accompanying consolidated statements of operations.

As a result of amending its Credit Agreement in April 2011 (Note 10), the senior lenders of the Company were issued equity interests giving the senior lenders a 10% ownership interest in the Company. The Company made aggregate principal and interest payments to its senior lenders of $1,819,939 and $1,389,101 in the 2012 and 2011.

As a result of amending its Credit Agreement in April 2011, $6,580,194 of related party seller notes and $6,689,164 of related party subordinated notes were forgiven.

During the years ended December 31, 2012 and 2011, the Company paid consulting fees of $250,000 to a related party. The related party is an entity that is majority owned by the Company's Chief Executive Officer. The related party provides the Company with senior leadership services. The related party is also entitled to receive an incentive bonus based on financial performance. The Company paid the related entity incentive bonus of $123,935 and $0 in 2012 and 2011, respectively.

During the years ended December 31, 2012 and 2011, the Company paid miscellaneous fees and expenses of $48,123 and $210,587, respectively, to members' or companies affiliated by virtue of common ownership with members.

The Company groups its activities into three reportable segments. The Fuel Processing and Distribution ("FP&D") segment includes transmix refining, biodiesel refining, and distribution of finished products. The Services segment includes activities related to bulk fuel terminal operations, reclamation services, transportation, and maintenance. The Company does not allocate all administrative overhead to FP&D and Services. The unallocated portion remains in the Corporate segment. Corporate segment activities include cash management, debt financing activities, and other administrative costs that are not directly attributable to FP&D and Services. The Company conducts its business primarily in the southeastern United States. The Company does not have international operations.

standards for segment reporting (ASC 280), that engage in activities (a) from which revenues are earned and expenses incurred; (b) whose operating results are regularly reviewed by the CODM, which makes decisions about resources to be allocated to the business segments and assess their financial performance; and, (c) for which discrete financial information is available.

Segment managers for the FP&D and Services segments are directly accountable to and maintain regular contact with the Company's CODM to discuss segment operating activities and financial performance. With concurrence and approval of the board of directors, the CODM approves annual capital budgets for major projects. However, business unit managers within the operating segments are responsible for decisions relating to project implementation and matters connected with daily operations.

The Company primarily evaluates the performance of operating segments using operating income. Interest expense, depreciation and amortization, and certain other items of income and expense, are not part of management's routine evaluation of segment performance.

The following tables illustrate reportable segment revenues and earnings together with reconciliation to consolidated results. Asset information, including capital expenditures, by segment is not used by management in its monitoring of performance and, therefore, is not reported by segment.

	For the Year Ended December 31, 2012

	FP&D		Services			Corporate			Eliminations			Total
Revenues	$	553,171,608	$	9,479,316		$	—		$	(5,251,775	)	$	557,399,149
Operating expenses		550,667,741		9,900,663			70,985			(5,251,775	)		555,387,614

Operating income (loss)		2,503,867		(421,347	)		(70,985	)		—			2,011,535
Interest expense		—		(77,163	)		(565,009	)		—			(642,172	)
Amortization of deferred financing costs		—		(7,229	)		(163,736	)		—			(170,965	)
Gain on extinguishment of payable		—		—			—			—			—
Gain from debt restructuring		—		—			—			—			—
Changes in fair value of interest rate swap		—		—			—			—			—
Litigation (loss)		—		(750,000	)		—			—			(750,000	)
Other		—		32,913			—			—			32,913

Total other income (expense)		—		(801,479	)		(728,745	)		—			(1,530,224	)

Income (loss) before income taxes	$	2,503,867	$	(1,222,826	)		(799,730	)	$	—		$	481,311

	For the Year Ended December 31, 2011

	FP&D			Services			Corporate			Eliminations			Total
Revenues	$	344,388,416		$	9,634,634		$	—		$	(4,713,931	)	$	349,309,119
Operating expenses		340,781,813			10,372,885			218,592			(4,713,931	)		346,659,359

Operating income (loss)		3,606,603			(738,251	)		(218,592	)					2,649,760
Interest expense		(36,160	)		(32,845	)		(1,293,160	)					(1,362,165	)
Amortization of deferred financing costs		—			—			(173,607	)		—			(173,607	)
Gain on extinguishment of payable		1,211,807			—			—			—			1,211,807
Gain from debt restructuring		—			—			472,283			—			472,283
Changes in fair value of interest rate swap		—			—			243,167			—			243,167
Other		(2,265,564	)		1,581,310			782,848			—			98,594

Total other income (expense)		(1,089,917	)		1,548,465			31,531			—			490,079

Income (loss) before income taxes	$	2,516,686		$	810,214		$	(187,061	)	$	—		$	3,139,839

The Company evaluated subsequent events through the date the financial statements were issued. No significant events have occurred requiring disclosure.

December 31,	2011		2010

Liabilities and Members' Equity
Current liabilities
Accounts payable and accrued liabilities	$	10,023,407	$	16,072,839
Current portion of long-term debt, including accrued interest payable of $1,242,135 in 2010		300,000		6,223,553
Current portion of capital lease payable		—		119,537
Current portion of related party seller notes and subordinated debt, including accrued interest payable of $951,964 in 2010		—		13,052,112
Derivative contract liability		—		243,167

Total current liabilities		10,323,407		35,711,208
Capital lease payable, net of current portion		—		44,039
Long-term debt, net of current portion		21,659,544		18,698,412
Revolver loan		10,500,000		7,149,703

Total liabilities		42,482,951		61,603,362

Commitments and contingencies (Note 12)
Members' Equity		25,586,392		3,261,165

Total liabilities and members' equity	$	68,069,343	$	64,864,527

Years Ended December 31,	2011			2010

Fuel revenues	$	343,734,426		$	239,056,044
Other revenues		5,574,553			5,420,144

Total revenues		349,308,979			244,476,188
Operating expenses
Cost of fuel		331,415,780			231,455,571
Operations and maintenance		8,522,908			7,616,070
Selling, general and administrative		3,973,413			4,113,244
Depreciation and amortization		2,858,429			3,079,234
Gain on disposal of equipment, net		(111,171	)		(179,994	)

Total operating expenses		346,659,359			246,084,125

Operating income (loss)		2,649,620			(1,607,937	)
Other income (expense)
Interest expense		(1,362,165	)		(3,692,194	)
Amortization of deferred financing cost		(173,607	)		(199,629	)
Gain on extinguishment of payable (Note 8)		1,211,807			—
Gain from debt restructuring, net (Note 9)		472,283			—
Changes in fair value of interest rate swap		243,167			281,097
Other		98,734			48,982

Total other income (expense)		490,219			(3,561,744	)

Income (loss) before benefit from income tax		3,139,839			(5,169,681	)
Benefit from income tax		—			1,050,696

Net income (loss)	$	3,139,839		$	(4,118,985	)

Net income (loss) per member unit
Net income (loss) available to unitholders	$	3,139,839		$	(4,118,985	)
Weighted-average member units outstanding		100,000			100,000
Earnings (loss) per member unit (basic and diluted)	$	31.40		$	(41.19	)

	Membership Interest			Accumulated Deficit			Total

Balance at December 31, 2009	$	25,600,519		$	(18,220,369	)	$	7,380,150
Net loss		—			(4,118,985	)		(4,118,985	)

Balance at December 31, 2010		25,600,519			(22,339,354	)		3,261,165
Capital contribution		4,000,000			—			4,000,000
Forgiveness of seller notes and accrued interest payable, net(Note 10)		6,580,194			—			6,580,194
Forgiveness of subordinated notes and accrued interest (Note 11)		6,689,164			—			6,689,164
Forgiveness of long-term debt in exchange for equity (Note 9)		1,515,016			—			1,515,016
Deconsolidation of subsidiary (Note 2)		(13,515,878	)		13,916,892			401,014
Net income		—			3,139,839			3,139,839

Balance at December 31, 2011	$	30,869,015		$	(5,282,623	)	$	25,586,392

Years Ended December 31,	2011			2010

Cash Flows from Operating Activities
Net income (loss)	$	3,139,839		$	(4,118,985	)
Adjustments to reconcile net income (loss) to net cash (used in) provided by operating activities:
Depreciation and amortization of property, plant and equipment		2,460,587			2,576,166
Amortization of intangibles		397,842			503,068
Amortization of deferred financing cost		173,607			199,629
Interest rolled into debt balances		759,360			560,000
Gain on extinguishment of trade payable (Note 8)		(1,211,807	)		—
Gain on debt restructuring (Note 9)		(472,283	)		—
Changes in fair value of derivative financial instrument		(243,167	)		(281,097	)
Gain on disposal of equipment		(111,171	)		(179,994	)
Provision for doubtful accounts		—			330,117
Deferred income tax benefit		—			(1,050,696	)
Changes in operating assets and liabilities, net of business deconsolidated:
Accounts receivables		(3,836,583	)		(1,292,370	)
Inventories		(4,164,446	)		(3,331,332	)
Other current assets and other assets		(489,065	)		80,193
Accounts payable and accrued expenses		(3,416,091	)		6,599,252
Tax refund receivable and income taxes payable		925,388			2,550,697

Net cash (used in) provided by operating activities		(6,087,990	)		3,144,648

Cash Flows from Investing Activities
Proceeds from disposal of equipment		91,000			200,975
Collections of notes receivable		1,786			—
Purchases of property, plant and equipment		(935,215	)		(352,561	)

Net cash used in investing activities		(842,429	)		(151,586	)

Cash Flows from Financing Activities
Equity contribution		4,000,000			—
Cash distributed to deconsolidated subsidiary (Note 2)		(251,442	)		—
Payment made to a member		(125,000	)		—
Repayment of capital lease payable		(163,576	)		(171,341	)
Payment of financing costs		(306,364	)		(20,678	)
Repayment of long-term debt		(894,243	)		(1,875,946	)
Proceeds from revolver loan		22,100,000			1,097,180
Repayment of revolver loan		(18,749,703	)		(31,971	)

Net cash provided by (used in) financing activities		5,609,672			(1,002,756	)

(Decrease) increase in cash and cash equivalents		(1,320,747	)		1,990,306
Cash and cash equivalents, beginning of year		3,261,802			1,271,496

Cash and cash equivalents, end of year	$	1,941,055		$	3,261,802

The Company operates a motor fuel bulk storage facility located in Birmingham, Alabama. The Company purchases, blends, markets, and transports light petroleum products to its customers in the Birmingham area. The Company also operates a transportation mixture ("transmix") distillation tower that extracts gasoline and diesel fuel from commingled motor fuels. Through AEC, the Company offers terminal cleaning and petroleum reclamation services.

The accompanying consolidated financial statements are the responsibility of the management of AEC Holdings LLC. The Company eliminates all significant intercompany balances and transactions in the consolidation.

On September 29, 2011, the Company deconsolidated its wholly owned subsidiary WCRO. Pursuant to the Stock Purchase Agreement between the Company and WCRO's new parent, W. C. Rice Oil Holdings LLC ("WCROH"), the Company distributed 100% of the common stock in WCROH for consideration of one dollar ($1.00). In accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 810, when a parent sells or otherwise ceases to own all or part of its ownership interest in its subsidiary, and as a result, the parent no longer has a controlling interest in the subsidiary, deconsolidation of that subsidiary is generally required.

Prior to deconsolidation, WCRO conducted marketing efforts to sell and distribute gasoline and diesel products to wholesale, industrial, and commercial accounts. The Company transferred all of these activities to AEC prior to deconsolidation. In addition, WCRO sold substantially all of its tangible, long-lived assets to AEC for amount that approximates net book value at the date of transfer. These tangible, long-lived assets consisted of trucks, office equipment and leasehold improvements. Since AEC continues to conduct these business activities, the deconsolidation of WCRO is not a "discontinued operation" in the context of current accounting standards.

At the date of deconsolidation, the net deficit of WCRO consisted of the following:

On September 29, 2011, the Company entered into a management services contract with WCRO to handle routine transition affairs together with post-deconsolidation administrative matters including but not limited to bookkeeping, sales tax returns, business license filings and ad valorem filings. WCRO compensates the Company for these services at a rate of $100 per hour. In its sole discretion, WCRO has the right to terminate the agreement at any time. For the year ended December 31, 2011, the Company had not provided meaningful services under the agreement. Consequently, the Company had not billed WCRO any fees under the agreement. At December 31, 2011, the Company did not reflect any amounts due to or due from WCRO or WCROH.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America ("GAAP") requires management to make estimates that affect the reported amounts of assets, liabilities, revenues, and expenses and the disclosure of contingent assets and liabilities. Actual results could differ from these estimates. Significant estimates include:

The Company's financial instruments consist primarily of cash and cash equivalents, accounts receivable, accounts payable, debt instruments, and derivative financial instruments. The carrying amounts of financial instruments, other than the debt instruments and derivative financial instruments, are representative of their fair values due to their short maturities. The Company's long-term debt agreement bears interest at market rates, and thus management believes their carrying amounts approximate fair value.

Financial instruments that potentially subject the Company to concentration of credit risk are cash and cash equivalents and trade accounts receivable. All of the Company's cash and cash equivalents were fully insured at December 31, 2011 and 2010 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 will revert to $250,000 per depositor at each financial institution and the Company's cash balances may again exceed federally insured limits. The Company maintains its cash and cash equivalents in financial institutions it considers to be of high credit quality.

During the year ended December 31, 2010, no customer accounted for more than 10% of total revenue and revenues from the top 10% of customers accounted for approximately 85% of total revenues. Accounts receivable outstanding relating to these customers was approximately 81% of total accounts receivable at December 31, 2010.

During the year ended December 31, 2011, purchases from two major suppliers accounted for approximately 58% and 18% of total purchases. Accounts payable outstanding relating to these two major suppliers were approximately 46% and 0% of total accounts payable at December 31, 2011.

During the period ended December 31, 2010, purchases from two major suppliers accounted for approximately 45% and 21% of total purchases. Accounts payable outstanding relating to these two major suppliers were approximately 21% and 16% of total accounts payable at December 31, 2010.

The Company considers all highly liquid investments with original maturities when purchased of three months or less to be cash equivalents. All of our non-interest bearing cash balances were fully insured at December 31, 2011 and December 31, 2010 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 will revert to $250,000 per depositor at each financial institution, and our non-interest bearing cash balances may again exceed federally insured limits.

The Company's policy is to capitalize interest cost incurred on debt during the construction of major projects. For the years ended December 31, 2011 and 2010, the Company did not capitalize any interest costs.

In accordance with FASB ASC 360-10-05, Impairment or Disposal of Long-Lived Assets, 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 be tested for possible impairment, the Company first compares 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. In management's opinion, no impairment of long-lived assets exists at December 31, 2011 and 2010.

In its review of long-lived assets for possible impairments, the Company made significant estimates and assumptions about future events and changes in circumstances for its biodiesel refinery. At December 31, 2011 and 2010, the carrying value of the Company's biodiesel refinery, net of accumulated depreciation, amounted to approximately $6,289,000 and $6,608,000, respectively. Due to operating economics, the biodiesel refinery has been dormant for approximately four years. In February 2012, the Company commenced actions to recommission and restart the biodiesel refinery. To bring the biodiesel refinery to operable condition, the restart process requires application of resources including but not limited to construction, engineering, licensing, and recertification with governmental agencies.

The Company developed its future financial estimates on the basic assumption that the refinery will return to operational status in the near term. A return to operational status is a significant assumption that underlies the Company's estimate for future, undiscounted cash flows expected from operating the biodiesel refinery. In the event that the actual outcome of future events differs from the Company's operational and financial estimates, the resulting change could have a material effect on the consolidated statement of operations, consolidated balance sheet, and members' equity.

Basic net income (loss) per member unit excludes dilution and is computed using the weighted-average number of member units outstanding. Diluted net income per member unit reflects the potential dilution that could occur if securities or other contracts to issue member units were exercised or converted into member units or resulted in the issuance of member units that then shared in the earnings. The Company has no potentially dilutive securities or contracts outstanding.

The Company reports federal excise tax on motor fuels on a gross basis. Federal and state excise taxes included in revenue and cost of fuel approximated $19,619,000 and $18,508,000 for the years ended December 31, 2011 and 2010, respectively.

Advertising costs, which are included in selling, general and administrative expense, are expensed as incurred and are not material to the consolidated financial statements.

Deferred financing costs that are directly and incrementally associated with new borrowings are capitalized and are amortized on a method approximating the effective interest method.

measures and the highest and best use of nonfinancial assets. The update provides additional disclosure requirements regarding Level 3 fair value measurements and clarifies certain other existing disclosure requirements. The ASU is effective for the Company for annual periods beginning after December 15, 2011. The Company does not expect the impact of adopting this ASU to have a material effect on the Company's consolidated financial statements, but the adoption of this ASU may require additional disclosures.

The Company estimates that additional $150,000 will be incurred subsequent to December 31, 2011 to complete the construction in progress.

Amortization expense for the years ended December 31, 2011 and 2010 was $397,842 and $503,068, respectively. The annual estimated amortization expense related to these intangibles for each of the five succeeding fiscal years is $0.316 million, $0.288 million, $0.253 million, $0.204 million, and $0.164 million.

On April 4, 2011, the Company agreed to satisfy fully a trade payable for an amount less than its carrying amount of $2,851,807. The Company entered into a settlement agreement with a third party product supplier which provides mutual release of all parties and dismissed arbitral and court proceedings. Pursuant to the agreement, the Company paid the product supplier $1,550,000 in cash and transferred real estate with a book value of $90,000. For the year ended December 31, 2011, the Company recognized a gain from the extinguishment of this trade payable amounting to approximately $1,212,000.

December 31,	2011		2010

Term Loan to a bank secured by substantially all of the assets of the Company.	$	21,959,544	$	24,800,680
Note payable to a financial corporation, payable in monthly installments of $2,386 including interest at 8.675%, secured by equipment, maturing, September 23, 2011.		—		20,717
Note payable to a financial corporation, payable in monthly installments of $2,386 including interest at 8.675%, secured by equipment, maturing, September 23, 2011.		—		20,717
Note payable to a financial corporation, payable in monthly installments of $2,279 including interest at 8.2%, secured by equipment, maturing, May 31, 2011.		—		10,364
Note payable to a financial corporation, payable in monthly installments of $2,282 including interest at 8.2%, secured by equipment, maturing, September 23, 2011.		—		12,870
Note payable to a financial corporation, payable in monthly installments of $5,051 including interest at 8.68%, secured by equipment, maturing, December 2011.		—		56,617

	$	21,959,544	$	24,921,965
Less current portion		300,000		6,223,553

	$	21,659,544	$	18,698,412

At December 31, 2011 and 2010, the Company had a secured credit agreement ("Credit Agreement") with the senior lender that consisted of a revolver loan and term loan, both collateralized by substantially all of the Company's assets. At December 31, 2010, the current portion of long-term debt, as reported in the balance sheet, includes accrued interest payable for the term loan and revolver loan amounting to $1,242,135.

The Credit Agreement contains affirmative, negative and various financial covenants under which the Company is obligated. As of December 31, 2010, the Company was not in compliance with these covenants. At December 31, 2010, the Company was in default under terms of the Credit Agreement and the bank issued notice of acceleration.

and conversion of these debts into equity, b) requires the members contribute $4,000,000 to the Company, c) requires the issuance of equity interests to the senior lenders to the extent of 10% of the issued and outstanding interests of the Company, d) requires the payment of mandatory minimum principal payments on a quarterly basis beginning March 31, 2011 and continuing quarterly thereafter until December 31, 2014, e) modification of the financial covenants and a term loan prepayment arrangement whereby the Company is 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. Excess cash flow is defined generally as earnings before interest, taxes, depreciation, and amortization as reduced for certain capital expenditures, interest on bank debt, tax payments, changes in working capital, and other customary modifications. The senior lenders also forgave $6,014,369 of principal, accrued interest and late fees associated with the term loan and $376,429 of accrued interest attributable to the revolver. The Amended Credit Agreement did not modify the carrying value of the revolver loan principal balance and reinstated the revolver loan commitment to the extent of $15,000,000. The Company accounted for the above debt restructuring as a troubled debt restructuring and recorded the gain or loss on the debt restructuring based on troubled debt restructuring accounting.

Generally, a restructuring of debt constitutes a troubled debt restructuring for accounting purposes if the creditor for economic or other reasons related to the debtor's financial difficulties grants a concession to the debtor that it would not otherwise consider. Pursuant to FASB ASC 470-60, the amendment to the Credit Agreement has been accounted for as a troubled debt restructuring due to the concessions granted by the senior lenders. As a result, unamortized balances of deferred financing fees ($87,000), the fair value of the 10% equity grant to senior lenders ($1,515,000) and the direct cost associated with the debt restructuring ($307,000) were netted against the sum of the carrying value of the term loan ($23,559,000) and accrued interest payable ($1,676,000) at the date of modification. This results in a new carrying amount of approximately of $23,326,000. The difference between this new carrying amount of the term loan and the sum of the restructured liability of $18,848,000 and the estimated future interest of the restructured loan amounting to $4,005,000 using an interest rate of 5.5% was recorded as a gain on debt restructuring for the year ended December 31, 2011 amounting to $472,283.

The carrying value of the term loan under the Amended Credit Agreement at December 31, 2011 was $21,959,554 and does not equate to the total future principal cash payments of $18,698,412 due under the term debt as a result of accounting for a troubled debt restructuring. The difference between the carrying value of the term loan and the restructured liability will be recognized by the Company as reduced interest costs over the term of the Amended Credit Agreement. Interest payments to the term loan over the term of the Amended Credit Agreement will be applied to the carrying value of the term loan.

The following table reconciles senior lender records to the Company's modified carrying value of its term loan.

	Term loan per Senior Lender			Reconciling Items			Carrying Value of Term Debt

Term loan principal balance at December 31, 2010	$	23,558,545		$	—		$	23,558,545
Add accrued interest—Term Loan		959,289			—			959,289
Add accrued interest—Revolver		—			282,846			282,846

Balance at December 31, 2010		24,517,834			282,846			24,800,680
Accrued interest—Term loan for period January 1, 2011 through April 1, 2011		323,531			(3,555	)		319,976
Accrued interest—Revolver for period January 1, 2011 through April 1, 2011		—			92,555			92,555
Accrued late fees		21,415			—			21,415

		24,862,780			371,846			25,234,626
Forgiveness of Term loan principal		(4,710,133	)		4,710,133			—
Forgiveness of Term loan accrued interest		(1,282,820	)		1,282,820			—
Forgiveness of late fees		(21,415	)		21,415			—

		18,848,412			6,386,214			25,234,626
Fair value of 10% equity grant to senior lenders		—			(1,515,016	)		(1,515,016	)
Gain from troubled debt restructuring at April 1, 2011, before direct cost incurred in the debt restructuring and write-off of deferred financing cost amounting to $393,540		—			(865,823	)		(865,823	)

Modified carrying value at April 1, 2011		18,848,412			4,005,375			22,853,787
Principal payments		(150,000	)		—			(150,000	)
Interest payments applied to reduce modified carrying value pursuant to FASB ASC 470-60-35-6		—			(744,243	)		(744,243	)

Term loan principal balance at December 31, 2011	$	18,698,412		$	3,261,132		$	21,959,544

The reconciling items above are primarily due to the accounting for the troubled debt restructuring for the term loan.

The maturity date of the revolver loan and term loan is April 1, 2015. As of December 31, 2011, the Company is in compliance with the financial covenants of the Amended Credit Agreement. The amount available under the revolver loan at December 31, 2011 and 2010 was $4,500,000 and $0, respectively. The revolver loan and term loan accrues 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 London interbank offered rates (LIBOR) plus applicable margin which is tied to the Company's financial performance. The Company has the option to elect the type of interest when funds are advanced or to move tranches of the debt between the two types of interest. At December 31, 2011, the Company elected the LIBOR option for $5,000,000 of its revolver and $18,000,000 of the term loan. The LIBOR option for the revolver loan and term loan is from December 28, 2011 to January 30, 2012. The remaining portions for both revolver loan and term loan were included under the bank's base commercial lending rate plus applicable margin.

The following tables illustrate those portions subject to the base commercial lending rate and the LIBOR rate at December 31, 2011 and 2010.

The following table represents the estimated maturities of the Company's long-term debt:

Since the specified amount of excess cash flow cannot presently be determined with any amount of specificity, the Company has classified the entire outstanding balance of the long-term debt in accordance with the fixed contractual repayment terms as of December 31, 2011.

In 2008, the Company signed promissory notes in the aggregate principal amount of $7,500,000, payable in equal and consecutive monthly installments at an annual simple interest rate of 8%. The notes expire on June 1, 2018. The outstanding balance under the promissory notes and accrued interest payable is $6,040,418 and $544,929, respectively at December 31, 2010. These notes are subordinate to the security interests of the senior lender.

In 2009, the Company borrowed $2,000,000 and $3,500,000 from a related party. Interest accrues monthly at the annual rate of 12% and 16%, respectively. Interest is payable monthly and principal is due in a single lump sum in April 2014 and November 2013. In 2010, interest payable rolled into the subordinated debt balance amounted to $560,000. The outstanding balance of the subordinated debt and accrued interest payable is $6,060,000 and $406,764, respectively, at December 31, 2010.

The Company maintains general liability insurance with limits and deductibles that management believes prudent in light of the exposure of the Company to loss and the cost of the insurance.

The Company is presently under examination by the Alabama Department of Revenue ("ADOR") for tax years 2008, 2009, 2010, and 2011. In May 2012, ADOR completed its examination and the Company settled the assessment amounting to approximately $1,000.

The Company is subject to various claims and litigation arising in the ordinary course of business. In the opinion of management, the outcome of such matters will not have a material effect on the liquidity, financial position or results of operations of the Company.

The Company has operating leases involving real estate. These leases are noncancellable and expire on various dates through 2013. The expense incurred on operating leases for the years ended December 31, 2011 and 2010 was approximately $271,100 and $371,000, respectively.

At December 31, 2011, future minimum rental payments required under non-cancellable operating leases with terms in excess of one year are as follows:

The Company deconsolidated WCRO on September 29, 2011 and WCRO's taxable income through that date, which is included in the Company's reported results, is approximately $64,000. As of December 31, 2010, the Company had sufficient net federal tax loss carryforwards to offset this taxable income. As a result, no income tax expense is recorded for the year ended December 31, 2011.

After deconsolidation, the accompanying statements do not reflect any income tax benefit or liability related to the operations of WCRO at December 31, 2011. The components of benefit from income tax relating to the operations of WCRO at December 31, 2011 and 2010 consist of the following:

A reconciliation of the significant differences between the U.S. federal statutory tax rate of 35% and the effective income tax rate on income (loss) before taxes is as follows:

Deferred income taxes reflect the net tax effects of temporary differences between the carrying amount of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Significant components of the net deferred tax asset were as follows:

The Company recorded valuation allowances at December 31, 2010 related to certain deferred tax assets due to the uncertainty of the ultimate realization of the future benefits from those assets. The valuation allowances cover deferred tax assets, primarily tax loss carryforwards in tax jurisdictions where there is uncertainty as to the ultimate realization of a benefit from those tax losses. As of December 31, 2010, the Company had federal tax loss carryforwards of $2,229,579. The federal tax loss carryforwards will expire in 2030. Due to deconsolidation of WCRO that became effective on September 29, 2011, the Company will not benefit from these tax attributes.

The IRS commenced an examination of WCRO's U.S. income tax returns for the years ended October 31, 2005, October 31, 2006, October 31, 2007, December 31, 2008, and December 31, 2009 in the first quarter of 2011. The examination remains in progress. The IRS has not submitted findings or notice of examination changes. At this time, the Company cannot determine the amount of additional payment, if any, that may be due.

The Company is exposed to certain market risks relating to its ongoing business operations. These risks include exposure to fluctuations in interest rates as well as changing commodity prices.

The Company enters into interest rate swaps in accordance with its risk management strategy that do not meet the criteria for hedge accounting. Although these derivatives do not qualify as hedges, they have the economic impact of mitigating interest rate risk. An interest rate swap was entered into to manage interest rate risk associated with the Company's fixed-rate borrowings on July 21, 2008. The notional amount of the interest rate swap was $22,031,100 with a maturity date of August 1, 2011. The interest rate swap agreements are accounted for on a mark to market basis through current earnings even though they were not acquired for trading purposes.

As of December 31, 2011 and 2010, the total notional amount of the Company's receive-fixed/pay-variable interest rate swap was $0 and $15,232,050, respectively. The fair value of outstanding derivative financial instruments was $0 and $243,167 at December 31, 2011 and 2010, respectively. The

15. Derivative Financial Instruments and Fair Value Measurements (Continued)

Company recorded derivative contract gains of $243,167 and $281,097 in the consolidated statement of operations for the years ended December 31, 2011 and 2010, respectively.

The Company periodically enters into futures contracts to mitigate cash flow volatility associated with fuel product price changes. The Company does not designate these instruments as hedging instruments. These instruments are accounted for on a mark to market basis with changes in the fair value reflected in cost of fuel. The Company recorded derivative contract losses of $611,500 and $618,143 in the consolidated statement of operations for the years ended December 31, 2011 and 2010, respectively. As of December 31, 2011 there were no open derivative contracts associated with fuel products. As of December 31, 2010, the Company had 26 open contracts to manage fuel price risk.

The Company has adopted FASB ASC 820, which defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. FASB ASC 820 applies to other accounting pronouncements that require or permit fair value measurements; however, it does not require any new 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.

The Company's 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 input that is significant to the fair value measurement.

The following table provides the assets and liabilities carried at fair value measured on a recurring basis:

As discussed in Note 9, the Company granted the senior lenders a 10% equity interest in the Company. The Company determined the fair value of the 10% senior lender equity grant using Level 3 inputs. Level 3 inputs are unobservable in that there is little or no market data. The Company developed its own assumptions to assess the fair value of the equity grant. Generally, the assumptions

15. Derivative Financial Instruments and Fair Value Measurements (Continued)

included a compilation of comparable earnings data (from publicly available sources) for companies similarly situated to the Company. From this information, the Company developed an earnings multiple pattern and computed a discounted cash flow analysis ("DCF") using reasonable estimates for future earnings. The Company used the DCF analysis to determine an indicated enterprise value, net of estimated debt. The Company multiplied the indicated enterprise value by 10% and further reduced this amount by applying a non-controlling interest discount. The Company derived $1,515,016 as the fair value for the 10% equity grant to its senior lenders.

The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy:

On January 1, 2009, the Company initiated a 401(k) savings plan for all full time employees who have completed three months of service. Matching contributions will be a discretionary percentage, determined by the Company. During 2011 and 2010, the Company recorded compensation expense of approximately $155,000 and $165,000, respectively, related to the discretionary contributions that have been recorded in accompanying consolidated statements of operations.

As a result of amending its Credit Agreement in April 2011 (Note 9), the senior lenders of the Company were issued equity interests giving the senior lenders a 10% ownership interest in the Company. In 2011, the Company made aggregate principal and interest payments to its senior lenders of $1,389,101.

As a result of amending its Credit Agreement in April 2011, $6,580,194 of related party seller notes and $6,689,164 of related party subordinated notes were forgiven.

During the years ended December 31, 2011 and 2010, the Company paid consulting fees of $250,000 to an entity that is majority owned by the Company's Chief Executive Officer.

During the years ended December 31, 2011 and 2010, the Company paid miscellaneous fees and expenses of $180,587 and $125,219, respectively, to members' or companies affiliated by virtue of common ownership with members.

The Company groups its activities into three reportable segments. The Fuel Processing and Distribution ("FP&D") segment includes transmix refining and distribution of finished products. The Services segment includes activities related to bulk fuel terminal operations, reclamation services, transportation, and maintenance. The Company does not allocate all administrative overhead to FP&D and Services. The unallocated portion remains in the Corporate segment. Corporate segment activities include cash management, debt financing activities, and other administrative costs that are not directly attributable to FP&D and Services. The Company conducts its business primarily in the southeastern United States. The Company does not have international operations.

The FP&D and Services segments are separately managed under a structure that includes "Segment Managers" who report to the Company's "Chief Operating Decision Maker" (CODM) (as defined in ASC 280). The CODM is the Company's Chief Executive Officer who reports to the Board of Directors. FP&D and Services represent components of the Company, as described in accounting standards for segment reporting (ASC 280), that engage in activities (a) from which revenues are earned and expenses incurred; (b) whose operating results are regularly reviewed by the CODM, which makes decisions about resources to be allocated to the business segments and assess their financial performance; and, (c) for which discrete financial information is available.

	For the Year Ended December 31, 2011

	FP&D			Services			Corporate			Eliminations			Total
Revenues	$	344,388,416		$	9,634,634		$	—		$	(4,713,931	)	$	349,309,119
Operating expenses		340,781,813			10,372,885			218,592			(4,713,931	)		346,659,359

Operating income		3,606,603			(738,251	)		(218,592	)		—			2,649,760
Interest expense		(36,160	)		(32,845	)		(1,293,160	)		—			(1,362,165	)
Amortization of deferred financing costs		—			—			(173,607	)		—			(173,607	)
Gain on extinguishment of payable		1,211,807			—			—			—			1,211,807
Gain from debt restructuring		—			—			472,283			—			472,283
Changes in fair value of interest rate swap		—			—			243,167			—			243,167
Other		(2,265,564	)		1,581,310			782,848			—			98,594

Total other income (expense)		(1,089,917	)		1,548,465			31,531			—			490,079

Income (loss) before income taxes	$	2,516,686		$	810,214		$	(187,061	)	$	—		$	3,139,839

We have audited the accompanying consolidated financial statements of Direct Fuels Partners, L.P. and subsidiaries ("Partnership"), which comprise the consolidated balance sheets as of December 31, 2012, 2011 and 2010, and the related consolidated statements of operations, partners' equity, and cash flows for the years then ended, and the related notes to the consolidated financial statements.

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditor's judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity's preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity's internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Direct Fuels Partners, L.P. and subsidiaries as of December 31, 2012, 2011 and 2010, and the results of their operations and their cash flows for the years then ended in accordance with accounting principles generally accepted in the United States of America.

December 31,	2012		2011

Assets
Current assets
Cash and cash equivalents	$	2,543,558	$	4,229,228
Accounts receivable, net of allowance for doubtful accounts of $49,891 and $60,000, respectively		10,773,545		6,340,211
Excise tax and other receivables		4,627,890		838,394
Inventories		6,424,542		9,537,399
Other current assets		946,435		2,432,536

Total current assets		25,315,970		23,377,768
Property, plant and equipment
Land and improvements		568,759		568,759
Buildings and improvements		2,317,351		2,246,104
Electrical and instrumentation		782,953		751,487
Pumps, pipe, and miscellaneous equipment		5,572,859		4,961,927
Office equipment, furniture and fixtures		358,569		349,783
Processing units and tanks		9,054,913		8,462,448
Vehicles		129,296		92,364

Total property, plant and equipment		18,784,700		17,432,872
Less accumulated depreciation		10,041,704		9,010,154

Net property, plant and equipment		8,742,996		8,422,718
Long-term receivable		—		80,000
Deferred financing costs, net of accumulated amortization of $665,742 and $311,230, respectively		563,135		603,345
Deferred public offering costs		804,247		—

Total assets	$	35,426,348	$	32,483,831

December 31,	2012			2011

Liabilities and Partners' Equity
Current liabilities
Trade payables	$	10,828,615		$	9,017,550
Accrued expenses		1,635,218			1,613,530
Current portion of long-term debt		16,716,667			1,700,004
Derivative financial instruments		33,410			—
Revolver loan		350,109			137,601

Total current liabilities		29,564,019			12,468,685
Derivative financial instruments		—			79,756
Long-term debt, net of current portion		—			7,958,329

Total liabilities		29,564,019			20,506,770

Commitments and contingencies
Partners' equity
General partner		322,557			147,739
Preferred equity		7,581,545			16,488,895
Limited partners—common units		(12,863,746	)		(11,197,070	)
Limited partners—subordinated units		10,821,973			6,537,497

Total partners' equity		5,862,329			11,977,061

Total liabilities and partners' equity	$	35,426,348		$	32,483,831

Direct Fuels Partners, L.P. and Subsidiaries

Consolidated Statements of Operations

Years Ended December 31,	2012			2011

Revenues
Fuel revenues	$	332,172,363		$	261,073,711
Other revenues		594,841			483,645

Total revenues		332,767,204			261,557,356

Operating expenses
Cost of fuel		312,703,644			237,856,840
Operations and maintenance		2,465,277			2,028,942
Selling, general and administrative		3,812,144			4,509,638
Depreciation		1,032,132			959,297

Total operating expenses		320,013,197			245,354,717

Operating income		12,754,007			16,202,639
Other expenses
Interest expense		810,273			1,072,164
Amortization of deferred financing costs		354,512			293,035
Loss on early extinguishment of subordinated debt		—			583,303
Changes in fair value of interest rate swap		(46,346	)		79,756

Total other expenses		1,118,439			2,028,258

Income before taxes		11,635,568			14,174,381
Provision for state margin taxes		82,407			219,641

Income from continuing operations		11,553,161			13,954,740
Income from discontinued operations		—			1,569,381
(Loss) on sale of discontinued operations		—			(69,879	)

Net income	$	11,553,161		$	15,454,242

Direct Fuels Partners, L.P. and Subsidiaries

Consolidated Statements of Partners' Equity

							Limited Partners

	General Partner			Preferred Equity			Limited Partners
	General Partner			Preferred Equity			Common			Subordinated			Total
Balance, December 31, 2010	$	(123,738	)	$	14,790,277		$	(11,779,126	)	$	(114,751	)	$	2,772,662
Issuance of preferred equity, net of issuance costs		—			2,101,810			—			—			2,101,810
Partner distributions paid in kind		—			(497,772	)		(1,606,828	)		—			(2,104,600	)
Partner distributions paid in cash		(45	)		(1,783,644	)		(4,463,364	)		—			(6,247,053	)
Net income		271,522			1,878,224			6,652,248			6,652,248			15,454,242

Balance, December 31, 2011		147,739			16,488,895			(11,197,070	)		6,537,497			11,977,061
Redemption of preferred units		—			(9,190,244	)		—			—			(9,190,244	)
Partner distributions paid in cash		(60	)		(2,526,437	)		(5,951,152	)		—			(8,477,649	)
Net income		174,878			2,809,331			4,284,476			4,284,476			11,553,161

Balance, December 31, 2012	$	322,557		$	7,581,545		$	(12,863,746	)	$	10,821,973		$	5,862,329

Direct Fuels Partners, L.P. and Subsidiaries

Consolidated Statements of Cash Flows

Years Ended December 31,	2012			2011

Cash flows from operating activities:
Net income	$	11,553,161		$	15,454,242
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation		1,032,132			959,297
Loss on early extinguishment of subordinated debt		—			583,303
Amortization of deferred financing costs		354,512			293,035
Changes in fair value of interest rate swap		(46,346	)		79,756
Gain (loss) on sale of property, plant, and equipment		356			(101,671	)
Provision for doubtful accounts		30,000			30,000
Changes in operating assets and liabilities:
Accounts receivable		(4,463,334	)		(1,905,170	)
Excise tax and other receivables		(3,789,496	)		3,194,603
Inventories		3,112,857			(3,506,309	)
Other current assets		1,486,102			(62,247	)
Long term note receivable		80,000
Trade payables and accrued expenses		1,832,753			4,181,038

Net cash provided by operating activities		11,182,697			19,199,877

Cash flows from investing activities:
Purchases of property, plant and equipment		(1,352,886	)		(566,838	)
Proceeds from sale of property, plant and equipment		120			7,000,000

Net cash (used in) provided by investing activities		(1,352,766	)		6,433,162

Cash flows used in financing activities:
Borrowings on revolver loan		348,314,533			281,790,461
Principal payments on revolver loan		(348,102,025	)		(284,857,678	)
Borrowings on term loan		8,758,333			—
Principal payments on term loan		(1,700,000	)		(7,200,000	)
Payment of public offering costs		(804,247	)		—
Redemption of preferred units		(9,190,244	)		(5,500,000	)
Payment of financing costs		(314,303	)		(378,865	)
Payment of equity issuance cost		—			(2,789	)
Cash distributions to partners		(8,477,648	)		(6,247,053	)

Net cash used in financing activities		(11,515,601	)		(22,395,924	)

(Decrease)/Increase in cash and cash equivalents		(1,685,670	)		3,237,115
Cash and cash equivalents, beginning of the year		4,229,228			992,113

Cash and cash equivalents, end of the year	$	2,543,558		$	4,229,228

Direct Fuels Partners, L.P. and Subsidiaries

Notes to Consolidated Financial Statements

Direct Fuels Partners, L.P. is a Delaware limited partnership formed to acquire the partnership interests of Insight Equity Acquisition Partners, LP. The consolidated financial statements include the accounts of Direct Fuels Partners, L.P. and its subsidiaries, Direct Fuels OLP GP, LLC and Insight Equity Acquisition Partners, LP, all of which are wholly-owned (collectively hereinafter referred to as the "Partnership").

The Partnership has operated a motor fuel terminal and processing facility in Texas since inception in May 2003. In late 2007, the Partnership began operating an ethanol terminal in the Dallas-Fort Worth area. The Partnership also completed construction of a biodiesel production facility in January 2008 and began producing biodiesel for sale to its customers in early February 2008. In July 2010, the Partnership sold the ethanol terminal and in April 2011, the Partnership sold the biodiesel production facility. Since the biodiesel production operations and cash flows could be clearly distinguished, operationally from the rest of the Partnership, the operating results have been classified as discontinued operations. See Note 3 as to the discussion and presentation of their discontinued operations.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. The accounting estimates that require the most significant, difficult and subjective judgment include:

The consolidated financial statements include the accounts of Direct Fuels Partners, L.P. and the consolidated accounts of all its subsidiaries. The entities included in these consolidated accounts are all wholly owned and are Insight Equity Acquisition Partners, LP and Direct Fuels OLP GP, LLC. All significant intercompany balances and transactions have been eliminated in consolidation.

The Partnership's financial instruments consist primarily of cash and cash equivalents, accounts receivable, accounts payable, derivative financial instruments and long-term debt instruments. The carrying amounts of financial instruments, other than the long-term debt instruments and derivative financial instruments, are representative of their fair values due to their short maturities. The Partnership's long-term debt agreement bears interest at market rates, and management believes its carrying amount approximates fair value. As discussed in Note 12, the derivative financial instruments are recorded at fair value.

Financial instruments that potentially subject the Partnership to concentration of credit risk are cash and cash equivalents and trade accounts receivable. The Partnership maintains its cash and cash equivalents in excess of federally insured limits in financial institutions it considers to be of high credit quality. All of our non-interest bearing cash balances were fully insured at 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 2013, insurance coverage will revert to $250,000 per depositor at each financial institution, and our non-interest bearing cash balances may again exceed federally insured limits.

Credit losses from customers have been within management's expectations, and the Partnership performs ongoing credit evaluations of its customers and generally does not require collateral.

Customer A represented 38% and 46% of the trade receivable balance as of December 31, 2012 and 2011, respectively. Customer B represented 31%, and 38% of the trade receivable balance as of December 31, 2012 and 2011, respectively. Customer C represented 19%, and 0% of the trade receivable balance as of December 31, 2012 and 2011, respectively. No other customer balance exceeded 10% of the total trade receivable balance as of December 31, 2012 and 2011.

Customer A represented 45% and 44% of revenues for the years ended December 31, 2012 and 2011, respectively. Customer B represented 37% of revenues for the years ended December 31, 2012 and 2011. No other customer represented 10% or more of revenues in any of the periods noted above.

The Partnership's largest supplier of motor fuel products provided 49% and 50% of motor fuel supply for the years ended December 31, 2012 and 2011, respectively. The second largest supplier of motor fuel products provided 10% and 2% of motor fuel supply for the years ended December 31, 2012 and 2011, respectively. The Partnership's third largest supplier of motor fuel products provided 9% and 10% of motor fuel supply for the years ended December 31, 2012 and 2011, respectively. The Partnership's fourth largest supplier of motor fuel products provided 5% and 10% of motor fuel supply for the years ended December 31, 2012 and 2011, respectively. No other supplier provided more than 10% of motor fuel supply in any of the periods noted above.

Unanticipated national or international events could result in a curtailment of motor fuel supplies to the Partnership, thereby adversely affecting motor fuel sales.

The Partnership considers all highly liquid investments with original maturities when purchased of three months or less to be cash equivalents.

Accounts receivable are comprised primarily of amounts owed to the Partnership through its motor fuel deliveries and are presented net of an allowance for doubtful accounts. The majority of trade receivables are due 10 days from the invoice date.

The Partnership maintains allowances for estimated losses resulting from the inability of its customers to make required payments. The Partnership estimates its allowances based on specifically

identified amounts that are believed to be uncollectible, which are determined based on historical experience and management's assessment of the general financial conditions affecting the Partnership's customer base. If the financial condition of the Partnership's customers were to deteriorate, resulting in an impairment of their ability to make payments, additional allowances might be required. After all attempts to collect a receivable have failed, the receivable is written off against the allowance.

As of December 31, 2012 and 2011, excise tax and other receivables comprised primarily of excise tax receivable. No allowance for doubtful accounts has been recorded for excise tax and other receivables as management believes that these are collectible.

Inventories consist of motor fuel products stored at terminal storage that can be sold over a truck loading rack. Motor fuel inventories are stated at the lower of cost or market using the average cost method.

Property, plant and equipment are stated at cost. Depreciation is computed over the estimated useful lives of the assets by the straight-line method for financial reporting purposes.

In accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Topic 360, Accounting for the Impairment or Disposal of Long-Lived Assets, 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 be tested for possible impairment, the Partnership first compares 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. The Partnership reclassified for all periods presented the operations of the facilities meeting the accounting criteria as either being sold or held for sale as discontinued operations in the consolidated statements of operations. There was no change to reported net income for the periods as a result of the reclassification. See Note 3 for a further discussion of discontinued operations.

Deferred public offering costs that are directly and incrementally associated with professional fees incurred related to a potential public offering are deferred and will be charged against the proceeds of the offering.

The Partnership recognizes revenue related to motor fuels, net of trade discounts and allowances, in the reporting period in which the products are transferred from the Partnership's 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. Trade discounts and allowances are not generally given and have been insignificant for the periods presented.

The Partnership includes all fuel purchase costs, excise taxes and freight costs in cost of fuel.

Liabilities for loss contingencies, including environmental remediation costs not within the scope of FASB ASC 410, Accounting for Asset Retirement Obligations, arising from claims, assessments, litigation, fines, and penalties and other sources, are recorded when it is probable that a liability has been incurred and the amount of the assessment and/or remediation can be reasonably estimated. Legal costs incurred in connection with loss contingencies are expensed as incurred. Recoveries of environmental remediation costs from third parties, which are probable of realization, are separately recorded as assets, and are not offset against the related environmental liability. No liabilities for environmental costs were required to be recorded at December 31, 2012 and 2011.

Fuel revenues and related cost of fuel include federal and state excise taxes of $5,966,495 and $15,738,857 for the years ended December 31, 2012 and 2011, respectively.

No provision is made in the accounts of the Partnership for U.S. federal income taxes as such taxes are liabilities of the individual partners. The tax returns and amounts of allocable Partnership revenues and expenses are subject to examination by federal and state taxing authorities. If such examinations result in changes to allocable Partnership revenues and expenses, the tax liability of the partners could change accordingly. In accordance with FASB ASC 740-10-30-7 in the Expenses—Income Taxes topic, the Partnership recognizes the effect of uncertain income tax positions, if any, only if those positions are more likely than not of being realized. Changes in recognition or measurement are reflected in the period in which the change in judgment occurs.

Starting in January 2007, the Partnership is subject to the Texas Margin Tax. No material deferred tax items arose as a result of this tax. The Texas Margin Tax liability is $137,485 and $146,797 as of December 31, 2012 and 2011, respectively, and is included in accrued expenses.

Deferred financing costs that are directly and incrementally associated with new borrowings are capitalized and are reported at cost and amortized over the term of the related debt using the effective interest method. In 2011, the Partnership wrote-off approximately $83,303 of deferred financing cost associated with the subordinated debt that was fully paid. The Partnership paid $314,303 and $378,865 in financing costs associated with its borrowings in 2012 and 2011, respectively.

The Partnership accounts for derivatives and hedging activities in accordance with FASB ASC Topic 815, Derivative and Hedging, as amended, which requires entities to recognize all derivative instruments as either assets or liabilities in the balance sheet at their respective fair values. Subsequent changes in the fair values of derivatives not designated as hedges are recognized in the Partnership's consolidated statements of operations. For derivatives designated as hedges, changes in fair value are either offset against the change in fair value, for the risk being hedged, of the assets and liabilities through earnings, or recognized in accumulated other comprehensive income until the hedged item is recognized in earnings.

The Partnership utilizes derivative instruments in the form of an interest rate swap to manage interest rates associated with the interest on its Revolver loan in 2012 and 2011.

Certain amounts in the prior year's financial statements have been reclassified to conform to the current year presentation.

The Partnership reported the operations of the biodiesel terminal facility as discontinued operations in the consolidated statement of operations.

The following summarizes the financial information of the discontinued operations for the period presented:

On November 18, 2010, the Partnership entered into a credit agreement with a financial institution. The credit agreement consists of a Term and a Floating ("Revolver") loan, both of which are collateralized by substantially all of the Partnerships' assets. The Term loan was funded in the amount of $17,000,000 at closing. On October 22, 2012 the credit agreement was amended to create an additional term loan ("Additional Term"). The Additional Term loan was funded in the amount of $8,758,333 at closing. Proceeds of the Additional Term loan were used to redeem Class D Preferred equity as discussed in Note 8. The Term and the Additional Term loan are deemed to be a single term loan (collectively hereafter "Term Loan"). The Term Loan accrues interest monthly at a rate equal to (a) London interbank offered rates (LIBOR) plus a margin of 4.01% or (b) a rate equal to the highest of (i) the financial institution's commercial lending rate, (ii) the Federal Funds Open Rate plus ¹/2 of 1% in effect on such day or (iii) the daily LIBOR rate plus 1% plus a margin of 3.01%. The Partnership has the option to move tranches of debt. The interest rate plus margin of the Term Loan was 6.26% and 4.209% for the two tranches at December 31, 2012. The monthly principal payments are $141,667 and the remaining outstanding balance is payable on November 28, 2013. The amount outstanding under the Term Loan was $16,716,667 and $9,658,333 at December 31, 2012 and 2011, respectively. The Term Loan is classified as a current liability as of December 31, 2012.

The Revolver had an original maximum advance amount of $11,000,000. On March 31, 2011, the credit agreement was amended to allow for the repayment of the subordinated debt and to increase the maximum advance amount on the Revolver to $14,000,000. On October 22, 2012 the credit agreement was amended to allow an advance (Specified Advance) on the Revolver up to $541,667 to complete the redemption of Class D Preferred equity as discussed in Note 8. The Revolver accrues interest monthly at a rate equal to (a) LIBOR plus a margin of 2.5% or (b) a rate equal to the highest of (i) the financial institution's commercial lending rate, (ii) the Federal Funds Open Rate plus ¹/2 of 1% in effect on such day or (iii) the daily LIBOR rate plus 1% plus a margin of 1.5%. The Specified Advance accrued interest monthly at a rate equal to (a) LIBOR plus a margin of 2.51% or (b) a rate equal to the highest of (i) the financial institution's commercial lending rate, (ii) the Federal Funds Open Rate

plus ¹/2 of 1% in effect on such day or (iii) the daily LIBOR rate plus 1% plus a margin of 1.51%. Repayments on the Revolver were applied first to the Specified Advance. The Specified Advance was fully repaid before December 31, 2012.The Partnership has the option to move tranches of debt between the two types of interest.

The interest rate plus margin of the Revolver was 4.75% at December 31, 2012. The amount outstanding as of December 31, 2012 and 2011 is $350,109 and $137,601, respectively. The Revolver will mature on November 28, 2013. In accordance with FASB ASC 470-10-45, the outstanding balance of the New Revolver was classified as a current liability as of December 31, 2012. The Revolver has undrawn availability of $13,143,828 and $12,343,810 as of December 31, 2012 and 2011, respectively.

On August 29, 2012 the credit agreement was amended to increase the annual capital expenditure limit.

In addition, the Revolver contains affirmative, negative and various financial covenants under which the Partnership is obligated. The Partnership is in compliance with these covenants as of December 31, 2012 and 2011.

The Partnership has entered into preliminary discussions with the financial institution to create a new credit agreement prior to maturity. The Partnership expects to have a new credit agreement in place with terms at least as favorable to the Partnership as the existing credit agreement before November 28, 2013.

On April 23, 2010, the Partnership entered into a subordinated debt agreement with an investor of the Partnership in the amount of $5,000,000. The proceeds of the subordinated debt were used to pay down the existing revolving credit facility. The subordinated debt is unsecured and bears an annual interest rate of 16% which is paid quarterly. On November 18, 2010, the subordinated debt agreement was amended to conform to the refinancing of the existing revolver loan. The amount outstanding under the subordinated debt arrangement at December 31, 2010 was $5,000,000. On April, 1, 2011 the Partnership paid off the outstanding principal balance of the subordinated debt agreement in the amount of $5,000,000 and accrued interest of $200,000. Due to the early payoff of the subordinated debt agreement, the Partnership incurred an early termination fee of $500,000 and this amount and the write-off of the carrying value of the deferred financing cost associated with the subordinated debt amounting to $83,303 is presented as loss on early extinguishment of the subordinated debt in the consolidated statements of operations. The subordinated debt was to mature on May 18, 2014.

The Partnership maintains general liability insurance with limits and deductibles that management believes prudent in light of the exposure of the Partnership to loss and the cost of the insurance.

varies from period to period. Due to fluctuations in the price and the volume, the annual purchase obligation cannot be determined.

The Partnership has entered into a registration rights agreement with the private investors under which it has agreed to (a) use commercially reasonable efforts to prepare and file with the Securities and Exchange Commission a shelf registration statement, within 90 days of the closing of an initial public offering, to permit the resale of the common units held by the private investors and (b) to use commercially reasonable efforts to cause the shelf registration statement to be declared effective within 180 days of the closing of the proposed initial public offering. The Partnership is required to pay liquidated damages if the shelf registration statement is not declared effective by 180 days following the closing of the proposed initial public offering, if the shelf registration statement is not maintained in accordance with the agreement and with respect to any common units required to be included in the shelf registration statement that are not included. The liquidated damages are payable in cash unless prohibited by the credit facilities. The maximum liquidated damages amount that the Partnership could be required to pay is estimated to be $2 per unsold registrable security held by the Private Investors after an initial public offering. No accrual has been made in the accompanying consolidated financial statements related to this matter, as payment is not considered probable at this time.

The Partnership is subject to various claims and litigation arising in the ordinary course of business. There are no known claims or pending litigation as of December 31, 2012.

In 2009, the Partnership entered into an agreement with an employee of the Partnership and concurrently advanced $80,000 to the employee. This amount was expensed in 2012.

In 2010, the Partnership entered into a credit agreement with an investor of the Partnership as discussed in Note 5. The debt on this agreement of $5,000,000 was paid in full on April 1, 2011.

For the period of June 8, 2007 through December 31, 2007, the general partner held 80% of the incentive distribution rights, 740,104 Class A common units, 3,240,104 subordinated units and 1,500,000 deferred participation units. Private investors held 2,500,000 Class B common units, warrants to purchase 2,500,000 Class A common units for $20 per unit, and 20% of the incentive distribution rights. The Class B common units can be redeemed at $20 per unit at the option of the Partnership until the closing date of an initial public offering. In May 2008, the private investors exchanged their warrants and Class B Common units to the Partnership for 2,500,000 Class A common units.

The common units and the subordinated units are considered separate classes of limited partner interest. The principal difference between the common units and subordinated units is that, in any quarter during the subordination period, the holders of the subordinated units are entitled to receive the minimum quarterly distribution only after the common units have received the minimum quarterly distribution plus arrearages from prior quarters. Subordinated units will not accrue arrearages. The

subordination period will end if the Partnership meets the financial tests in the partnership agreement or in the event of an initial public offering or sale transaction.

The deferred participation units convert into subordinated units on a one for one basis upon the occurrence of an initial public offering or a sale transaction. The number of units that can be converted is based on the initial public offering or sales transaction per unit price and an equal number of common units held by the private investor are cancelled. Until conversion the deferred participation units have no voting or distribution rights.

Incentive distribution rights entitle their holders to certain distributions of excess available cash after the Partnership has achieved certain target distribution levels after the occurrence of an initial public offering. The incentive distribution rights have no voting rights. Refer to the partnership agreement for additional information and terms of the partners' equity units.

The Partnership issued five tranches of non-convertible preferred units in lieu of cash distributions to the existing preferred and common unitholders. The following table outlines the five transactions:

On October 22, 2012, the Partnership purchased all of the Class D Preferred units and paid accrued distributions thereon. The non-convertible preferred units received distributions in priority to the convertible preferred and common units and received liquidation value equal to the purchase price plus any unpaid distributions whether or not declared. The total redemption amount paid was $9,645,750. Prior to redemption, the Partnership has the option to redeem the non-convertible preferred units at any time for cash at liquidation value plus $.40 per unit if redeemed on or before March 31, 2011 or $.20 per unit if after March 31, 2011 but before March 31, 2012. If the Partnership redeems the non-convertible preferred units for cash after March 31, 2012 the units will be redeemed at liquidation value. The non-convertible preferred units do not have voting rights except non-convertible preferred unitholders will be entitled to vote as a separate class on any matter on which unitholders are entitled to vote that adversely affects the rights or preferences of the non-convertible preferred unitholders. The non-convertible preferred units were issued to the holders of convertible preferred common units in the same ratio as distributions that were owed to the respective unitholders.

The Partnership issued three separate tranches of convertible preferred units and the following table is the outstanding convertible preferred units as of December 31, 2012 and 2011:

The convertible preferred units receive distributions in priority to the common units and would receive liquidation value equal to the purchase price plus any unpaid distributions whether or not declared. The convertible preferred units can convert into Class A common units at any time according to a conversion ratio. The conversion ratio is on a one-for-one basis but a conversion adjustment can occur if there is a change in outstanding units. The Partnership has the option to redeem the preferred units at any time for cash at liquidation value. The preferred units have the same voting rights as the common units. The preferred units were issued to the holders of common units in the same ratio of common unit ownership.

Allocation of Net Income (Loss)—Allocation of net income (loss) is based on the terms of the partnership agreement. Preferred Class D units will have income allocated to them to the extent required to make the capital account equal to the liquidation value. The liquidation value is defined as the total issue value plus any distributions accrued or not paid. Preferred D has priority income allocation among all units. Preferred Class C, B, and A units will have income equal to the respective class distribution that accrues whether or not declared. Income is allocated in the following priority: Preferred Class C, B, then A. Any remaining net income or loss is then allocated to the general partner (2%); holders of the common units (49%) and to the holders of the subordinated units (49%).

Distributions are paid when declared by the general partner. Distributions are based on the terms of the partnership agreement. Unpaid cumulative distribution as of December 31, 2012 and 2011 amounted to approximately $1,730,000 and $2,097,000, respectively. On February 15, 2013, the Partnership paid approximately $1.7 million in distributions to Common and Preferred A, B, and C unitholders.

Under the limited partnership agreement, the unitholders are entitled to receive a quarterly distribution of available cash to the extent there is sufficient cash from operations after establishment of cash reserves and payment of fees and expenses. The distributions for the period October 1, 2010 to December 31, 2010 were in kind distributions. The distributions for the period January 1, 2011 to September 30, 2012 were all cash distributions. The following provides a summary of distributions paid either cash or in kind by the Partnership:

Date Paid	Period Covered by Distribution	Type	Distribution per Unit		Total Distribution

August 15, 2011	April 1, 2011 - June 30, 2011	Common	$	.45	$	1,606,827
		Preferred A	$	.65	$	162,500
		Preferred B	$	.65	$	45,297
		Preferred C	$	.65	$	34,230
		Preferred D	$	.80	$	373,269
November 15, 2011	July 1, 2011 - September 30, 2011	Common	$	.45	$	1,487,803
		Preferred A	$	.65	$	162,500
		Preferred B	$	.65	$	45,297
		Preferred C	$	.65	$	34,230
		Preferred D	$	.80	$	367,610
February 17, 2012	October 1, 2011 - December 31, 2011	Common	$	.45	$	1,487,803
		Preferred A	$	.65	$	162,500
		Preferred B	$	.65	$	45,297
		Preferred C	$	.65	$	34,230
		Preferred D	$	.80	$	367,610
May 14, 2012	January 1, 2012 - March 31, 2012	Common	$	.45	$	1,487,803
		Preferred A	$	.65	$	162,500
		Preferred B	$	.65	$	45,297
		Preferred C	$	.65	$	34,230
		Preferred D	$	.80	$	367,610
August 14, 2012	April 1, 2012 - June 30, 2012	Common	$	.45	$	1,487,803
		Preferred A	$	.65	$	162,500
		Preferred B	$	.65	$	45,297
		Preferred C	$	.65	$	34,230
		Preferred D	$	.80	$	367,610
October 22, 2012	July 1, 2012 - October 21, 2012	Preferred D	$	.99	$	455,505
November 13, 2012	July 1, 2012 - September 30, 2012	Common	$	.45	$	1,487,803
		Preferred A	$	.65	$	162,500
		Preferred B	$	.65	$	45,297
		Preferred C	$	.65	$	34,230

The Partnership has adopted a defined contribution retirement plan. All employees are eligible to participate in the plan on the first of the month following 30 days of employment. In 2012, the Partnership made matching contributions up to 100% of the participant's contribution limited to 6% of the participant's annual compensation. The Partnership's matching contributions become fully vested after the participant has completed one year of service. The Partnership made matching contributions to the Plan of $61,451 and $81,946, for the years ended December 31, 2012 and 2011, respectively. All contributions by participants are fully vested.

The following is a summary of supplemental cash flow information transactions and non-cash transactions:

The Partnership entered into an interest rate swap agreement in accordance with its risk management strategy. The interest rate swap did not meet the criteria for hedge accounting. Although this interest rate swap did not qualify as a hedge, it does have the economic impact of mitigating interest rate exposure. This interest rate swap agreement is accounted for on a mark to market basis through current earnings even though they were not acquired for trading purposes.

In January, 2011, the Partnership entered into an interest rate swap agreement related to the Term Loan and had a notional amount of $6,400,000. This agreement effectively fixed the interest rate before margin on the related debt at 1.80%. The fair value of the liability associated with this swap contract was $33,410 at December 31, 2012 and $79,756 at December 31, 2011.

The tables below provide data about the carrying values of derivatives that are not designated as hedge instruments:

FASB ASC Topic 820, which defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. FASB ASC Topic 820 applies to other accounting pronouncements that require or permit fair value measurements; however, it does not require any new fair value measurements.

FASB ASC Topic 820 defines fair value as the exit price, which is the price that would be received to sell an asset or paid to transfer a liability in a transaction between market participants at the measurement date. FASB ASC Topic 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.

Although the Partnership utilizes mark to market quotes to assess the reasonableness of prices and valuation techniques, the Partnership does not have sufficient corroborating market evidence to support classifying these liabilities as Level 1.

A financial asset or liability's classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The following table provides the assets and liabilities carried at fair value measured on a recurring basis as of December 31, 2012:

The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as level 2 in the fair value hierarchy:

The Partnership has evaluated all subsequent events through March 22, 2013, the date the consolidated financial statements were available for issuance.

December 31,	2011		2010

Assets
Current assets
Cash and cash equivalents	$	4,229,228	$	992,113
Accounts receivable, less allowance for doubtful accounts of $60,000 and $30,000, respectively		6,340,211		4,465,042
Other receivables		838,394		4,032,996
Inventories		9,537,399		6,031,090
Other current assets		2,432,536		2,370,289
Assets held for sale		—		6,876,467

Total current assets		23,377,768		24,767,997
Property, plant and equipment
Land and improvements		568,759		394,514
Buildings and improvements		2,246,104		2,161,560
Electrical and instrumentation		751,487		769,836
Pumps, pipe, and miscellaneous equipment		4,961,927		4,866,258
Office equipment, furniture and fixtures		349,783		325,285
Processing units and tanks		8,462,448		8,275,952
Vehicles		92,364		99,564

Total property, plant and equipment		17,432,872		16,892,969
Less accumulated depreciation		9,010,154		8,055,929

Net property, plant and equipment		8,422,718		8,837,040
Long-term receivable		80,000		80,000
Deferred financing costs, net of accumulated amortization of $311,230 and $41,622, respectively		603,345		600,817

Total assets	$	32,483,831	$	34,285,854

December 31,	2011			2010

Liabilities and Partners' Equity
Current liabilities
Trade payables	$	9,017,550		$	5,371,642
Accrued expenses		1,613,530			1,078,399
Current portion of long-term debt		1,700,004			1,700,004
Revolver loan		137,601			3,204,818

Total current liabilities		12,468,685			11,354,863
Derivative financial instruments		79,756			—
Long-term debt, net of current portion		7,958,329			20,158,329

Total liabilities		20,506,770			31,513,192

Commitments and contingencies
Partners' equity
General partner		147,739			(123,738	)
Preferred equity		16,488,895			14,790,277
Limited partners—common units		(11,197,070	)		(11,779,126	)
Limited partners—subordinated units		6,537,497			(114,751	)

Total partners' equity		11,977,061			2,772,662

Total liabilities and partners' equity	$	32,483,831		$	34,285,854

Years Ended December 31,	2011			2010

Revenues
Fuel revenues	$	261,073,711		$	224,888,910
Other revenues		483,645			359,891

Total revenues		261,557,356			225,248,801

Operating expenses
Cost of fuel		237,856,840			214,117,150
Operations and maintenance		2,028,942			1,789,380
Selling, general and administrative		4,509,638			4,066,209
Depreciation		959,297			964,059

Total operating expenses		245,354,717			220,936,798

Operating income		16,202,639			4,312,003
Other expenses
Interest expense		1,072,164			2,452,143
Amortization of deferred financing costs		293,035			713,774
Loss on early extinguishment of subordinated debt		583,303			—
Changes in fair value of interest rate swap		79,756			(96,939	)
Loss on early extinguishment of revolver loan		—			1,303,340
Write-off of deferred financing costs		—			475,527

Total other expenses		2,028,258			4,847,845

Income (loss) before taxes		14,174,381			(535,842	)
Provision for state margin taxes		219,641			30,248

Income (loss) from continuing operations		13,954,740			(566,090	)
Income from discontinued operations		1,569,381			1,813,744
Impairment loss of property, plant and equipment		—			(1,700,000	)
(Loss) gain on sale of discontinued operations		(69,879	)		11,296,547

Net income	$	15,454,242		$	10,844,201

							Limited Partners

	General Partner			Preferred Equity			Limited Partners
	General Partner			Preferred Equity			Common			Subordinated			Total
Balance, December 31, 2009	$	(310,253	)	$	7,562,523		$	(10,516,543	)	$	(4,684,356	)	$	(7,948,629	)
Issuance of preferred equity, net of issuance costs		—			6,962,776			—			—			6,962,776
Partner distributions paid in kind		—			(1,253,499	)		(5,832,187	)		—			(7,085,686	)
Net income		186,515			1,518,477			4,569,604			4,569,605			10,844,201

Balance, December 31, 2010		(123,738	)		14,790,277			(11,779,126	)		(114,751	)		2,772,662
Issuance of preferred equity, net of issuance costs		—			2,101,810			—			—			2,101,810
Partner distributions paid in kind		—			(497,772	)		(1,606,828	)		—			(2,104,600	)
Partner distributions paid in cash		(45	)		(1,783,644	)		(4,463,364	)		—			(6,247,053	)
Net income		271,522			1,878,224			6,652,248			6,652,248			15,454,242

Balance, December 31, 2011	$	147,739		$	16,488,895		$	(11,197,070	)	$	6,537,497		$	11,977,061

Years Ended December 31,	2011			2010

Cash flows from operating activities:
Net income	$	15,454,242		$	10,844,201
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation		959,297			2,114,130
Loss on early extinguishment of subordinated debt		583,303			—
Amortization of deferred financing costs		293,035			713,774
Changes in fair value of interest rate swap		79,756			(96,939	)
Gain on sale of property, plant, and equipment		(101,671	)		(11,702,231	)
Provision for doubtful accounts		30,000			30,000
Loss on early extinguishment of revolver loan		—			1,303,340
Write-off of deferred financing costs		—			475,527
Impairment loss of property, plant and equipment		—			1,700,000
Realized loss on derivative financial instrument		—			(1,238,185	)
Changes in operating assets and liabilities:
Accounts receivable		(1,905,170	)		(208,146	)
Other receivables		3,194,603			(3,744,080	)
Inventories		(3,506,309	)		591,484
Other current assets		(62,247	)		(1,028,848	)
Trade payables and accrued expenses		4,181,038			(1,218,521	)

Net cash provided by (used in) operating activities		19,199,877			(1,464,494	)

Cash flows from investing activities:
Purchases of property, plant and equipment		(566,838	)		(251,606	)
Proceeds from sale of property, plant and equipment		7,000,000			16,000,000

Net cash provided by investing activities		6,433,162			15,748,394

Cash flows used in financing activities:
Borrowings on revolver loan		281,790,461			148,597,598
Principal payments on revolver loan		(284,857,678	)		(183,517,780	)
Borrowings on term loan		—			17,000,000
Principal payments on term loan		(7,200,000	)		(141,667	)
Borrowings on subordinated term loan		—			5,000,000
Payments on subordinated term loan		(5,500,000	)		—
Payment of financing costs		(378,865	)		(1,310,773	)
Payment of equity issuance cost		(2,789	)		(122,912	)
Cash distributions to partners		(6,247,053	)		—

Net cash used in financing activities		(22,395,924	)		(14,495,534	)

Increase (decrease) in cash and cash equivalents		3,237,115			(211,634	)
Cash and cash equivalents, beginning of the year		992,113			1,203,747

Cash and cash equivalents, end of the year	$	4,229,228		$	992,113

The Partnership has operated a motor fuel terminal and processing facility in Texas since inception in May 2003. In late 2007, the Partnership began operating an ethanol terminal in the Dallas-Fort Worth area. The Partnership also completed construction of a biodiesel production facility in January 2008 and began producing biodiesel for sale to its customers in early February 2008. In July 2010, the Partnership sold the ethanol terminal and in April 2011, the Partnership sold the biodiesel production facility. Since the ethanol terminal and the biodiesel production operations and cash flows that could be clearly distinguished, operationally from the rest of the Partnership, their operating results have been classified as discontinued operations. See Note 3 as to the discussion and presentation of their discontinued operations.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. The accounting estimates that require the most significant, difficult and subjective judgment include:

The Partnership's financial instruments consist primarily of cash and cash equivalents, accounts receivable, accounts payable, derivative financial instruments and debt instruments. The carrying amounts of financial instruments, other than the debt instruments, are representative of their fair values due to their short maturities. The Partnership's long-term debt agreement bears interest at market rates, and management believes its carrying amount approximates fair value. As discussed in Note 12, the derivative financial instruments are recorded at fair value.

Financial instruments that potentially subject the Partnership to concentration of credit risk are cash and cash equivalents and trade accounts receivable. The Partnership maintains its cash and cash equivalents in excess of federally insured limits in financial institutions it considers to be of high credit quality. All of our non-interest bearing cash balances were fully insured at December 31, 2011 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 2013, insurance coverage will revert to $250,000 per depositor at each financial institution, and our non-interest bearing cash balances may again exceed federally insured limits.

Credit losses from customers have been within management's expectations, and the Partnership performs ongoing credit evaluations of its customers and generally does not require collateral.

Customer A represented 38% and 34% of the trade receivable balance as of December 31, 2011 and 2010, respectively. Customer B represented 46%, and 42% of the trade receivable balance as of December 31, 2011 and 2010, respectively. No other customer balance exceeded 10% of the total trade receivable balance as of December 31, 2011 and 2010.

Customer A represented 37% and 28% of revenues for the years ended December 31, 2011 and 2010, respectively. Customer B represented 44% and 6% of revenues for the years ended December 31, 2011 and 2010, respectively. Customer C represented 3% and 15% of the revenues for the year ended December 31, 2011 and 2010, respectively. Customer D represented 1% and 15% of the revenues for the years ended December 31, 2011 and 2010, respectively. No other customer represented 10% or more of revenues in any of the periods noted above.

The Partnership's largest supplier of motor fuel products provided 50% and 42% of motor fuel supply for the years ended December 31, 2011 and 2010, respectively. The second largest supplier of motor fuel products provided 10% and 28% of motor fuel supply for the years ended December 31, 2011 and 2010, respectively. The Partnership's third largest supplier of motor fuel products provided 10% and 8% of motor fuel supply for the years ended December 31, 2011 and 2010, respectively No other supplier provided more than 10% of motor fuel supply in any of the periods noted above.

Unanticipated national or international events could result in a curtailment of motor fuel supplies to the Partnership, thereby adversely affecting motor fuel sales.

The Partnership considers all highly liquid investments with original maturities when purchased of three months or less to be cash equivalents.

The Partnership maintains allowances for estimated losses resulting from the inability of its customers to make required payments. The Partnership estimates its allowances based on specifically identified amounts that are believed to be uncollectible, which are determined based on historical experience and management's assessment of the general financial conditions affecting the Partnership's customer base. If the financial condition of the Partnership's customers were to deteriorate, resulting in an impairment of their ability to make payments, additional allowances might be required. After all attempts to collect a receivable have failed, the receivable is written off against the allowance.

In 2011, other receivable comprised primarily of excise tax receivable. In 2010, other receivables are comprised primarily of accrued biodiesel tax credits. Subsequent to December 31, 2010, the Partnership collected the biodiesel tax credits.

Property, plant and equipment are stated at cost. Depreciation is computed over the estimated useful lives of the assets by the straight-line method for financial reporting purposes.

Assets held for sale consists of land and biodiesel production facility is being carried at lower of its carrying amount or fair value less cost to sell. The facility was sold in 2011 as discussed in Note 3.

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. The Partnership reclassified for all periods presented the operations of the facilities meeting the accounting criteria as either being sold or held for sale as discontinued operations in the consolidated statements of operations. There was no change to reported net income for the periods as a result of the reclassification. The Partnership recorded no impairment expense for the year ended December 31, 2011. See Note 3 for a further discussion of discontinued operations and the 2010 impairment charge.

The Partnership recognizes revenue related to motor fuels, net of trade discounts and allowances, in the reporting period in which the products are transferred from the Partnership's 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 and determinable. Trade discounts and allowances are not generally given and have been insignificant for the periods presented.

The Partnership includes all fuel purchase costs, excise taxes and freight costs in cost of fuel.

Fuel revenues and related cost of fuel include federal and state excise taxes of $15,738,857 and $20,621,184 for the years ended December 31, 2011 and 2010, respectively.

Starting in January 2007, the Partnership is subject to the Texas Margin Tax. No material deferred tax items arose as a result of this tax. The Texas Margin Tax liability is $146,797 and $8,920 as of December 31, 2011 and 2010, respectively, and is included in accrued expenses.

Deferred financing costs that are directly and incrementally associated with new borrowings are capitalized and are reported at cost and amortized over the term of the related debt using the effective interest method. In 2010, the Partnership amended its credit agreement resulting in a reduced borrowing capacity and in accordance with FASB ASC 470-50-40-21, the Partnership wrote off $475,527 of deferred financing costs associated with costs previously capitalized associated with the reduced borrowing capacity. In 2011, the Partnership wrote-off approximately $83,303 of deferred financing cost associated with the subordinated debt that was fully paid. In 2010, the Partnership refinanced its existing revolver loan and wrote off $1,303,340 of deferred financing costs associated with revolver loan that was fully paid. The Partnership paid $378,865 and $642,439 in financing costs associated with its borrowings in 2011 and 2010, respectively.

The Partnership utilizes derivative instruments in the form of an interest rate swap to manage interest rates associated with the interest on its Revolver loan in 2011 and 2010.

Certain information provided for in prior year has been reclassified to conform to the current year presentation.

In July 2010, the Partnership sold its ethanol terminal facility to an unrelated party. The Partnership received gross cash proceed of $16.0 million and recognized a gain of $11.7 million as a result of this transaction. The net proceeds of the sale of the ethanol terminal facility were used to pay down the Revolver loan.

In 2010, the Partnership decided to sell the biodiesel terminal facility and accordingly reclassified this asset as Asset Held For Sale. On April 1, 2011, the Partnership sold the biodiesel terminal facility for $7.0 million. The Partnership recorded this asset at December 31, 2010 at the lower of carrying amount or fair value less cost to sell and recognized an impairment amounting to $1.7 million for the year ended December 31, 2010.

In evaluating the fair value of the biodiesel terminal facility, the Partnership determined the fair value measurements in their entirety fall into level 3 as the method is used to determine the fair value consisted primarily of quoted price for the asset.

The Partnership reported the operations of the ethanol terminal facility and biodiesel terminal facility as discontinued operation in the consolidated statement of operations.

The following summarizes the financial information of the discontinued operations for the periods presented:

Years Ended December 31,	2011			2010

Fuel revenues	$	4,968,491		$	9,183,379
Other revenues		2,890,295			3,893,967

Total revenues		7,858,786			13,077,346
Total operating expenses		(6,266,544	)		(10,872,172	)
Interest expense		(22,861	)		(391,430	)

Income from discontinued operations	$	1,569,381		$	1,813,744

Years Ended December 31,	2011			2010
Gain on sales of discontinued operations	$	168,383		$	11,702,231
Transaction costs		(238,262	)		(405,684	)

(Loss) gain on sales of discontinued operations	$	(69,879	)	$	11,296,547

December 31,	2011			2010
Accounts receivable	$	—		$	167,871
Other receivable		—			3,970,964
Inventory		—			914,272
Assets held for sale		—			6,876,467

Assets of discontinued operations	$	—		$	11,929,574

December 31,	2011			2010
Trade payables	$	—		$	159,779
Accrued expenses		—			23,534

Liabilities of discontinued operations	$	—		$	183,313

The Partnership had a secured credit agreement with a financial institution that consisted of a revolving credit facility ("Revolver") which was collateralized by substantially all of the Partnership's assets. The revolver loan was to mature on June 8, 2012.

On November 18, 2010, the Partnership refinanced its existing Revolver loan with a new financial institution. The new credit agreement consists of a Term and a Floating ("New Revolver") loan, both of which are collateralized by substantially all of the Partnerships' assets. The Term loan was funded in the amount of $17,000,000 at closing. Proceeds of the Term Loan were used to pay off the existing Revolver. The Term Loan accrues interest monthly at a rate equal to (a) London interbank offered rates (LIBOR) plus a margin of 4% or (b) a rate equal to the highest of (i) the financial institution's commercial lending rate, (ii) the Federal Funds Open Rate plus ¹/2 of 1% in effect on such day or (iii) the daily LIBOR rate plus 1% plus a margin of 3%. The Partnership has the option to move tranches of debt. The interest rate plus margin of the Term Loan was 6.25% and 4.27% for the two tranches at December 31, 2011. The monthly principal payments are $141,667 and the remaining outstanding balance is payable on November 28, 2013. The amount outstanding under the Term Loan was $9,658,333 and $16,858,333 at December 31, 2011 and December 31, 2010, respectively.

The New Revolver has a maximum advance amount of $11,000,000. The proceeds were used to pay off the existing Revolver and pay transaction costs. The New Revolver accrues interest monthly at a rate equal to (a) London interbank offered rates (LIBOR) plus a margin of 2.5% or (b) a rate equal to the highest of (i) the financial institution's commercial lending rate, (ii) the Federal Funds Open Rate plus ¹/2 of 1% in effect on such day or (iii) the daily LIBOR rate plus 1% plus a margin of 1.5%. The Partnership has the option to move tranches of debt between the two types of interest. The interest rate plus margin of the New Revolver was 4.75% at December 31, 2011. The amount outstanding as of December 31, 2011 and 2010 is $137,601 and $3,204,818, respectively. The New Revolver will mature on November 28, 2013. In accordance with FASB ASC 470-10-45, the outstanding balance of the New Revolver was classified as current liability as of December 31, 2011.

On March 31, 2011, the new credit agreement was amended to allow for the repayment of the subordinated debt and to increase the maximum advance amount on the New Revolver to $14,000,000.

In addition, the New Revolver contains affirmative, negative and various financial covenants under which the Partnership is obligated. The Partnership is in compliance with these covenants as of December 31, 2011 and 2010.

On April 23, 2010, the Partnership entered into a subordinated debt agreement with an investor of the Partnership in the amount of $5,000,000. The proceeds of the subordinated debt were used to pay down the existing revolving credit facility. The subordinated debt is unsecured and bears an annual interest rate of 16% which is paid quarterly. On November 18, 2010, the subordinated debt agreement was amended to conform to the refinancing of the existing revolver loan. The amount outstanding under the subordinated debt arrangement at December 31, 2010 was $5,000,000. On April 1, 2011 the Partnership paid off the outstanding principal balance of the subordinated debt agreement in the amount of $5,000,000 and accrued interest of $200,000. Due to the early payoff of the subordinated debt agreement the Partnership incurred an early termination fee of $500,000 and this amount and the write-off of the carrying value of the deferred financing cost associated with the subordinated debt amounting to $83,303 is presented as loss on early extinguishment of the subordinated debt in the consolidated statements of operations. The subordinated debt was to mature on May 18, 2014.

The combined aggregate maturities of long-term debt at December 31, 2011, are as follows:

The Partnership maintains general liability insurance with limits and deductibles that management believes prudent in light of the exposure of the Partnership to loss and the cost of the insurance.

The Partnership has entered into contracts with various suppliers of transmix product having original terms ranging from 12-48 months at an industry standard regional price index plus a margin. The Partnership is committed to purchase 100% of the transmix generated by these suppliers which varies from period to period. Due to fluctuations in the price and the volume, the annual purchase obligation cannot be determined.

closing of the proposed initial public offering, if the shelf registration statement is not maintained in accordance with the agreement and with respect to any common units required to be included in the shelf registration statement that are not included. The liquidated damages are payable in cash unless prohibited by the credit facilities. The maximum liquidated damages amount that the Partnership could be required to pay is estimated to be $2 per unsold registrable security held by the Private Investors after an initial public offering. No accrual has been made in the accompanying consolidated financial statements related to this matter, as payment is not considered probable at this time.

The Partnership is subject to various claims and litigation arising in the ordinary course of business. In the opinion of management, the outcome of such matters will not have a material effect on the financial position or results of operations of the Partnership.

In 2009, the Partnership entered into an agreement with an employee of the Partnership and concurrently advanced $80,000 to the employee. This amount will remain outstanding so long as the employee remains employed and shall be deducted against any future incentive payment pursuant to the agreement.

In 2010, the Partnership entered into a credit agreement with an investor of the Partnership as discussed in Note 5. The debt on this agreement of $5,000,000 was paid in full on April 1, 2011.

For the period of June 8, 2007 through December 31, 2007, the general partner held 80% of the incentive distribution rights, 740,104 Class A common units, 3,240,104 subordinated units and 1,500,000 deferred participation units. Private investors held 2,500,000 Class B common units, warrants to purchase 2,500,000 Class A common units for $20 per unit, and 20% of the incentive distribution rights. The Class B common units can be redeemed at $20 per unit at the option of the Partnership until the closing date of an initial public offering. In May 2008, the private investors exchanged its warrants and Class B Common units to the Partnership for 2,500,000 Class A common units.

The non-convertible preferred units receive distributions in priority to the convertible preferred and common units and would receive liquidation value equal to the purchase price plus any unpaid distributions whether or not declared. The Partnership has the option to redeem the non-convertible preferred units at any time for cash at liquidation value plus $.40 per unit if redeemed on or before March 31, 2011 or $.20 per unit if after March 31, 2011 but before March 31, 2012. If the Partnership redeems the non-convertible preferred units for cash after March 31, 2012 the units will be redeemed at liquidation value. The non-convertible preferred units do not have voting rights except non-convertible preferred unitholders will be entitled to vote as a separate class on any matter on which unitholders are entitled to vote that adversely affects the rights or preferences of the non-convertible preferred unitholders. The non-convertible preferred units were issued to the holders of convertible preferred common units in the same ratio as distributions that were owed to the respective unitholders.

The Partnership issued three separate tranches of convertible preferred units and the following table is the outstanding convertible preferred units as of December 31, 2011 and 2010:

Allocation of Net Income (Loss)—Allocation of net income (loss) is based on the terms of the partnership agreement. Preferred Class D units will have income allocated to them to the extent required to make the capital account equal to the liquidation value. The liquidation value is defined as the total issue value plus any distributions accrued whether or not paid. Preferred D has priority income allocation among all units. Preferred Class C, B, and A units will have income equal to the respective class distribution that accrues whether or not declared or paid. Income is allocated in the following priority: Preferred Class C, B, then A. Any remaining net income or loss is then allocated to the general partner (2%); holders of the common units (49%) and to the holders of the subordinated units (49%).

Distributions are paid when declared by the general partner. Distributions are based on the terms of the partnership agreement. Unpaid cumulative distribution as of December 31, 2011 and 2010 amounted to approximately $2,097,000 and $1,946,000, respectively. In February 2012, the Partnership distributed approximately $2.1 million.

Under the limited partnership agreement, the unitholders are entitled to receive a quarterly distribution of available cash to the extent there is sufficient cash from operations after establishment of cash reserves and payment of fees and expenses. The quarterly distributions for the period October 1, 2009 to December 31, 2010 are in kind distributions. The distributions for the period

January 1, 2011 to September 30, 2011 were all cash distributions. The following provides a summary of distributions paid either cash or in kind by the Partnership:

Date Paid	Period Covered by Distribution	Type	Distribution per Unit		Total Distribution

April 23,2010	October 1, 2009 - December 31, 2010	Common	$	.45	$	1,458,047
		Preferred A	$	.65	$	162,500
		Preferred B	$	.65	$	45,297
		Preferred C	$	.29	$	15,213
April 23,2010	January 1, 2010 - March 31, 2010	Common	$	.45	$	1,458,047
		Preferred A	$	.65	$	162,500
		Preferred B	$	.65	$	45,297
		Preferred C	$	.65	$	34,239
August 15, 2010	April 1, 2010 - June 30, 2010	Common	$	.45	$	1,458,047
		Preferred A	$	.65	$	162,500
		Preferred B	$	.65	$	45,297
		Preferred C	$	.65	$	34,230
		Preferred D	$	.7838	$	132,486
November 15, 2010	July 1, 2010 - September 30, 2010	Common	$	.45	$	1,458,047
		Preferred A	$	.65	$	162,500
		Preferred B	$	.65	$	45,297
		Preferred C	$	.65	$	34,230
		Preferred D	$	.6594	$	171,886
February 15, 2011	October 1, 2010 - December 31, 2010	Common	$	.45	$	1,458,047
		Preferred A	$	.65	$	162,500
		Preferred B	$	.65	$	45,297
		Preferred C	$	.65	$	34,230
		Preferred D	$	.694	$	245,986
May 15, 2011	January 1, 2011 - March 31, 2011	Common	$	.45	$	1,487,804
		Preferred A	$	.65	$	162,500
		Preferred B	$	.65	$	45,297
		Preferred C	$	.65	$	34,230
		Preferred D	$	.80	$	283,426
August 15, 2011	April 1, 2011 - June 30, 2011	Common	$	.45	$	1,606,827
		Preferred A	$	.65	$	162,500
		Preferred B	$	.65	$	45,297
		Preferred C	$	.65	$	34,230
		Preferred D	$	.80	$	373,269
November 15, 2011	July 1, 2011 - September 30, 2011	Common	$	.45	$	1,487,803
		Preferred A	$	.65	$	162,500
		Preferred B	$	.65	$	45,297
		Preferred C	$	.65	$	34,230
		Preferred D	$	.80	$	367,610

the participant's annual compensation. The Partnership's matching contributions become fully vested after the participant has completed one year of service. The Partnership made matching contributions to the Plan of $81,946 and $108,015, for the years ended December 31, 2011 and 2010, respectively. All contributions by participants are fully vested.

The following is a summary of supplemental cash flow information transactions and non-cash transactions:

The tables below provide data about the carrying values of derivatives that are not designated as hedge instruments:

The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as level 2 in the fair value hierarchy:

APPENDIX A
FORM OF AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF
EMERGE ENERGY SERVICES LP

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

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).

Biodiesel: A domestic, renewable fuel for diesel engines derived from natural oils, and which is comprised of monalkyl 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."

Closing Price: The last sale price on a day, regular way, or in case no sale takes place on that day, the average of the closing bid and asked prices on that day, regular way, in either case, as reported in the principal consolidated transaction reporting system for securities listed or admitted to trading on the principal national securities exchange on which the units of that class are listed or admitted to trading. If the units of that class are not listed or admitted to trading on any national securities exchange, the last quoted price on that day. If no quoted price exists, the average of the high bid and the low asked prices on that day in the over-the-counter market, as reported by the New York Stock Exchange or any other system then in use. If on any day the units of that class are not quoted by any organization of that type, the average of the closing bid and asked prices on that day as furnished by a professional market maker making a market in the units of the class selected by our board of directors. If on that day no market maker is making a market in the units of that class, the fair value of the units on that day as determined reasonably and in good faith by our board of directors.

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

Crude oil: A mixture of hydrocarbons that exists in liquid phase in underground reservoirs.

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.

Current market price: For any class of units listed or admitted to trading on any national securities exchange as of any date, the average of the daily closing prices for the 20 consecutive trading days immediately prior to that date.

Dry plant: An industrial site where slurried sand product is fed through a rotary dryer and screening system to be dried and screened in varying gradations. The finished product that emerges from the dry plant is then stored in silos before being transported to customers. Dry plants may also include a stone breaking machine and stone crusher.

EBITDA: A non-GAAP supplemental financial measure defined as net income (loss) before net interest expense, income tax expense and depreciation and depletion expense.

Energy Information Administration (EIA): The statistical and analytical agency within the U.S. Department of Energy.

Frac sand: A proppant used in the completion and re-completion of unconventional 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 of America.

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.

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.

Monocrystalline: Consisting of a single crystal rather than multiple crystals bonded together (polycrystalline). Monocrystalline frac sand typically exhibits higher crush strength than polycrystalline sand, as these structures are more prone to breaking down under high pressures than a single crystal.

Natural gas: A mixture of hydrocarbons (principally methane, ethane, propane, butanes and pentanes), water vapor, hydrogen sulfide, carbon dioxide, helium, nitrogen and other chemicals that occur naturally underground in a gaseous state.

Northern White sand: A monocrystalline sand with greater sphericity and roundness enabling higher crush strengths and conductivity.

Petroleum products: Petroleum products are obtained from the processing of crude oil (including lease condensate), natural gas and other hydrocarbon compound. Petroleum products include unfinished oils, liquefied petroleum gases, pentanes, aviation gasoline, motor gasoline, naphtha-type jet fuel, kerosene-type jet fuel, kerosene, distillate fuel oil, residual fuel oil, petrochemical feedstocks, special naphthas, lubricants, waxes, petroleum coke, asphalt, road oil, still gas and miscellaneous products.

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

Proven reserves: Quantity of sand estimated with reasonable certainty, from the analysis of geologic and engineering data, to be recoverable from well-established or known reservoirs with the existing equipment and under the existing operating conditions.

Refined Products: Hydrocarbon compounds, such as gasoline, diesel fuel, jet fuel and residential fuel, that are produced by a refinery.

Reserves: 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.

Silica: A chemically resistant dioxide of silicon that occurs in crystalline, amorphous and cryptocrystalline forms.

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 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.

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.

Until , 2013 (25 days after the date of this prospectus), all dealers that buy, sell or trade our common units, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers' obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

Set forth below are the expenses (other than underwriting discounts and commissions and the structuring fee) expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the SEC registration fee, the FINRA filing fee and the NYSE listing fee, the amounts set forth below are estimates.

The section of the prospectus entitled "The Partnership Agreement—Indemnification" beginning on page 202 discloses that we will generally indemnify officers, directors and affiliates of our general partner to the fullest extent permitted by the law against all losses, claims, damages or similar events and is incorporated herein by this reference. Reference is also made to the underwriting agreement to be filed as an exhibit to this registration statement, which provides for the indemnification of us and our general partner, its officers and directors, and any person who controls us and our general partner, including indemnification for liabilities under the Securities Act. Subject to any terms, conditions or restrictions set forth in the partnership agreement, Section 17-108 of the Delaware Revised Uniform Limited Partnership Act empowers a Delaware limited partnership to indemnify and hold harmless any partner or other person from and against any and all claims and demands whatsoever.

Subject to any terms, conditions or restrictions set forth in the limited liability company agreement, Section 18-108 of the Delaware Limited Liability Company Act empowers a Delaware limited liability company to indemnify and hold harmless any member or manager or other person from and against any and all claims and demands whatsoever.

Under the limited liability agreement of our general partner, in most circumstances, our general partner will indemnify the following persons, to the fullest extent permitted by law, from and against any and all losses, claims, damages, liabilities (joint or several), expenses (including legal fees and expenses), judgments, fines, penalties, interest, settlements or other amounts arising from any and all claims, demands, actions, suits or proceedings (whether civil, criminal, administrative or investigative):

As of the consummation of this offering, our general partner will maintain directors and officers liability insurance for the benefit of its directors and officers.

On April 27, 2012, in connection with our formation, we issued (i) a 2% general partner interest in us to Emerge GP, our general partner, in exchange for $40, and (ii) a 98% limited partner interest in us to Superior Silica Resources LLC in exchange for $1,960. The issuances were exempt from registration under Section 4(2) of the Securities Act. There have been no other sales of unregistered securities within the past three years.

(a) The following documents are filed as exhibits to this registration statement:

		Description

1.1	**	Form of Underwriting Agreement
3.1	*	Certificate of Limited Partnership of Emerge Energy Services LP
3.2	*	Amendment to Certificate of Limited Partnership of Emerge Energy Services LP
3.3	*	Limited Partnership Agreement of Emerge Energy Services LP
3.4	**	Form of Amended and Restated Limited Partnership Agreement of Emerge Energy Services LP
5.1	**	Opinion of Latham & Watkins LLP as to the legality of the securities being registered
8.1	**	Opinion of Latham & Watkins LLP relating to tax matters
10.1	**	Administrative Services Agreement by and among Insight Management Company LLC, Emerge Energy Services LP, and Emerge Energy Services GP LLC.
10.2	**	Form of Credit Agreement
10.3	**	Form of Long Term Incentive Plan
10.4	**	Form of Phantom Unit Agreement
10.5	*	Employment Letter, dated October 25, 2012, between Emerge Energy Services LP and Robert Lane
10.6	*†	Sand Supply Agreement, dated as of May 31, 2011, between Superior Silica Sands LLC and Schlumberger Technology Corporation.
10.7	*†	Sand Supply Agreement, dated as of May 31, 2011, between Superior Silica Sands LLC and BJ Services Company, U.S.A.
10.8	*†	Wet Sand Supply Agreement, dated as of July 17, 2012, between Superior Silica Sands LLC and Midwest Frac and Sands LLC.
10.9	*†	Dry Sand Tolling Agreement, dated July 17, 2012, between Superior Silica Sands LLC and Midwest Frac and Sands LLC
10.10	*†	Memorandum of Understanding, dated May 9, 2012, between Canadian National Railway Company and Superior Silica Sands LLC

Financial statement schedules are omitted because they are not required or the required information is shown in our financial statements or notes thereto.

The undersigned registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to

a court of appropriate jurisdiction the question of whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

Pursuant to the requirements of the Securities Act of 1933, as amended, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Southlake, State of Texas, on March 22, 2013.

Each person whose signature appears below appoints Ted W. Beneski and Warren B. Bonham, and each of them, any of whom may act without the joinder of the other, as his true and lawful attorneys-in-fact and agents, with full power of substitution and re-substitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this Registration Statement and any Registration Statement (including any amendment thereto) for this offering that is to be effective upon filing pursuant to Rule 462(b) under the Securities Act of 1933, as amended, and to file the same, with all exhibits thereto, and all other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done in connection therewith, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them, or their or his substitute and substitutes, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Act of 1933, as amended, this registration statement has been signed below by the following persons in the capacities indicated on March 22, 2013.

		Description

1.1	**	Form of Underwriting Agreement
3.1	*	Certificate of Limited Partnership of Emerge Energy Services LP
3.2	*	Amendment to Certificate of Limited Partnership of Emerge Energy Services LP
3.3	*	Limited Partnership Agreement of Emerge Energy Services LP
3.4	**	Form of Amended and Restated Limited Partnership Agreement of Emerge Energy Services LP
5.1	**	Opinion of Latham & Watkins LLP as to the legality of the securities being registered
8.1	**	Opinion of Latham & Watkins LLP relating to tax matters
10.1	**	Administrative Services Agreement by and among Insight Management Company LLC, Emerge Energy Services LP, and Emerge Energy Services GP LLC.
10.2	**	Form of Credit Agreement
10.3	**	Form of Long Term Incentive Plan
10.4	**	Form of Phantom Unit Agreement
10.5	*	Employment Letter, dated October 25, 2012, between Emerge Energy Services LP and Robert Lane
10.6	*†	Sand Supply Agreement, dated as of May 31, 2011, between Superior Silica Sands LLC and Schlumberger Technology Corporation.
10.7	*†	Sand Supply Agreement, dated as of May 31, 2011, between Superior Silica Sands LLC and BJ Services Company, U.S.A.
10.8	*†	Wet Sand Supply Agreement, dated as of July 17, 2012, between Superior Silica Sands LLC and Midwest Frac and Sands LLC.
10.9	*†	Dry Sand Tolling Agreement, dated July 17, 2012, between Superior Silica Sands LLC and Midwest Frac and Sands LLC
10.10	*†	Memorandum of Understanding, dated May 9, 2012, between Canadian National Railway Company and Superior Silica Sands LLC
10.11	*†	Wet Sand Services Agreement, dated April 7, 2011, by and between Superior Silica Sands LLC and Fred Weber, Inc.
10.12	*†	Amendment to Sand Supply Agreement, dated as of November 15, 2012 between Superior Silica Sands LLC and Schlumberger Technology Corporation.
21.1		List of subsidiaries of Emerge Energy Services LP
23.1		Consent of BDO USA, LLP
23.2		Consent of BDO USA, LLP
23.3	**	Consent of Latham & Watkins LLP (contained in Exhibit 5.1)
23.4	**	Consent of Latham & Watkins LLP (contained in Exhibit 8.1)
23.5		Consent of Short Elliot Hendrickson Inc.
23.6		Consent of Cooper Engineering Company, Inc.
23.7		Consent of Westward Environmental, Inc.


Delaware	1446		90-0832937
(State or Other Jurisdiction of Incorporation or Organization)	(Primary Standard Industrial Classification Code Number)		(I.R.S. Employer Identification Number)
1400 Civic Place, Suite 250 Southlake, Texas 76092 (817) 488-7775 (Address, Including Zip Code, and Telephone Number, Including Area Code, of Registrant's Principal Executive Offices)
Warren B. Bonham Vice President 1400 Civic Place, Suite 250 Southlake, Texas 76092 (817) 488-7775 (Name, Address, Including Zip Code, and Telephone Number, Including Area Code, of Agent for Service)
Copies to:
Ryan J. Maierson Latham & Watkins LLP 811 Main Street, Suite 3700 Houston, Texas 77002 (713) 546-5400		Alan Beck Vinson & Elkins L.L.P. 1001 Fannin Street, Suite 2500 Houston, Texas 77002 (713) 758-2222


Large accelerated filer o		Accelerated filer o		Non-accelerated filer ý (Do not check if a smaller reporting company)		Smaller reporting company o

Title of Each Class of Securities to be Registered	Proposed Maximum Aggregate Offering Price(1)(2)	Amount of Registration Fee




Common units representing limited partner interests	$100,000,000	$13,640

	Per Common Unit	Total

Public Offering Price	$	$
Underwriting Discount(1)	$	$
Proceeds to Emerge Energy Services LP (before expenses)	$	$


Public Common Units(1)		%(2)
Common Units held by Insight Equity and other private investors		%(2)
General Partner Units		%

Total	100.0	%

		Page

Summary			1
Our Relationship with Insight Equity			11
Risk Factors			12
Partnership Structure and Offering-Related Transactions			14
Organizational Structure After the Offering			15
Our Management			17
Principal Executive Offices and Internet Address			17
Summary of Conflicts of Interest and Duties			17
Implications of Being an Emerging Growth Company			18
The Offering			19
Summary Historical and Pro Forma Financial and Operating Data			23
Non-GAAP Financial Measures			26
Adjusted EBITDA			26
Operating Working Capital			28
Risk Factors			29
Risks Related to Our Business			29
Risks Inherent in an Investment in Us			49
Tax Risks to Common Unitholders			55
Use of Proceeds			60
Capitalization			63
Dilution			64
Our Cash Distribution Policy and Restrictions on Distributions			66
General			66
Unaudited Pro Forma Cash Available for Distribution for the Year Ended December 31, 2012			68
Provisions of our Partnership Agreement Relating to Cash Distributions			77
Distributions of Available Cash			77
Selected Historical and Pro Forma Financial and Operating Data			78
Selected Historical Financial and Operating Data			79
Selected Pro Forma Financial and Operating Data			81
Non-GAAP Financial Measures			83
Management's Discussion and Analysis of Financial Condition and Results of Operations			87
Overview			87
How We Generate Our Revenues			88
The Costs of Conducting Business			90
How We Evaluate Our Operations			92
Recent Trends and Outlook			94
Pro Forma Financial and Operating Data			95
Pro Forma Results of Operations			97
Pro Forma Liquidity and Capital Resources			98
Capital Requirements			100
Pro Forma Quantitative and Qualitative Disclosure About Market Risk			100
Historical Financial and Operating Data			103
Liquidity and Capital Resources			110
Off-Balance Sheet Arrangements			115

		Page

Contingencies			115
Contractual Obligations			116
Quantitative and Qualitative Disclosure About Market Risk			116
Critical Accounting Policies and Estimates			118
Asset Retirement Obligations			120
Impairment of Long-Lived Assets			120
Accounting for Contingencies			120
Recently Issued Accounting Pronouncements			121
Recently Enacted Legislation			121
Internal Controls and Procedures			121
Industry			123
Frac Sand Industry			123
Demand Trends			126
Extraction and Production Processes			128
Product Distribution			129
Supply Trends			129
Pricing			130
Fuel Processing and Distribution Industry			130
Overview			130
Supply and Demand			132
Business			134
Overview			134
Our Assets and Operations			140
Customers			153
Suppliers and Service Providers			154
Competition			155
Seasonality			156
Insurance			157
Environmental and Occupational Health and Safety Regulations			157
Employees			163
Legal Proceedings			163
Management of Emerge Energy Services LP			164
Directors and Executive Officers			165
Reimbursement of Expenses of Our General Partner			169
Executive Compensation			169
2012 Summary Compensation Table			170
Outstanding Equity Awards at December 31, 2012			172
Severance and Change in Control Benefits			173
Incentive Compensation Plans			173
Director Compensation			175
Certain Relationships and Related Party Transactions			177
Distributions and Payments to Our General Partner and its Affiliates			177
Agreements Governing the Transactions			178
Other Agreements with Affiliates			178
Procedures for Review, Approval and Ratification of Related-Person Transactions			179

		Page

Conflicts of Interest and Duties			180
Conflicts of Interest			180
Duties of our General Partner			185
Description of the Common Units			188
The Units			188
Transfer Agent and Registrar			188
Transfer of Common Units			188
The Partnership Agreement			190
Organization and Duration			190
Purpose			190
Cash Distributions			190
Capital Contributions			190
Voting Rights			191
Applicable Law; Forum, Venue and Jurisdiction			192
Limited Liability			192
Issuance of Additional Partnership Interests			194
Amendment of the Partnership Agreement			194
Merger, Consolidation, Conversion, Sale or Other Disposition of Assets			196
Dissolution			197
Liquidation and Distribution of Proceeds			197
Withdrawal or Removal of Our General Partner			198
Registration Rights			199
Transfer of General Partner Interest			199
Transfer of Ownership Interests in the General Partner			199
Change of Management Provisions			199
Limited Call Right			199
Non-Citizen Assignees; Redemption			200
Non-Taxpaying Assignees; Redemption			200
Meetings; Voting			201
Status as Limited Partner			201
Indemnification			202
Reimbursement of Expenses			202
Books and Reports			202
Right to Inspect Our Books and Records			203
Units Eligible for Future Sale			204
Material Federal Income Tax Consequences			205
Partnership Status			206
Limited Partner Status			207
Tax Consequences of Unit Ownership			207
Tax Treatment of Operations			214
Disposition of Common Units			217
Administrative Matters			221
Recent Legislative Developments			224
State, Local, Foreign and Other Tax Considerations			225
Investment in Emerge Energy Services LP by Employee Benefit Plans			226

		Page

Underwriting			228
Conflicts of Interest			230
Notice to Prospective Investors in the European Economic Area			230
Notice to Prospective Investors in the United Kingdom			231
Notice to Prospective Investors in Germany			232
Notice to Prospective Investors in the Netherlands			232
Notice to Prospective Investors in Switzerland			232
Validity of the Common Units			233
Experts			233
Where You Can Find More Information			233
Forward Looking Statements			233
Index to Financial Statements			F-1
Appendix A—Form of Partnership Agreement			A-1
Appendix B—Glossary of Terms			B-1

	As of December 31, 2012

	Predecessor Pro Forma Combined		Pro Forma Emerge Energy Services		Pro Forma Emerge Energy Services (As Adjusted)
	(in thousands)
Cash	$	1,465	$	4,009	$

Long-term debt (including current maturities)(1):
SSS		111,683		111,683
AEC Holdings		34,254		34,254
Direct Fuels		—		17,067
New revolving credit facility		—		—			(2)

Total long-term debt		145,937		163,004
Partners'/members' equity:
Partners'/members' equity		9,497		90,797		—
Common unitholders		—		—

Total partners' equity		9,497		90,797

Total capitalization	$	155,434	$	253,801	$


Assumed initial public offering price per common unit					$
Pro forma net tangible book value per unit before the offering(1)					$
Decrease in net tangible book value per unit attributable to purchasers in this offering

Less: Pro forma net tangible book value per unit after this offering(2)
Immediate dilution in net tangible book value per common unit to new investors(3)(4)					$

	Units Acquired				Total Consideration

	Number	Percent			Amount	Percent
General partner and affiliates(1)(2)(3)				%	$			%
Public common unitholders				%	$			%

Total			100.0	%	$		100.0	%

			(in thousands)

	Book value of net assets contributed		$
	Less: Distribution to SSS, AEC Holdings and DF Parent from net proceeds of this offering

	Total consideration		$

Contractual Obligation	Total		Less Than 1 Year		1-3 Years		3-5 Years

	(in thousands)
Long-Term Debt (Including Interest)	$	123,341	$	11,184	$	23,487	$	88,670	—
Customer Advances		4,043		4,043		—		—	—
Weber Wet Sand Purchases(1)		22,123		5,947		12,433		3,743	—
Midwest Frac Wet Sand		23,200		2,400		4,800		4,800	11,200
Canadian National		45,000		3,375		8,156		9,563	23,906
Natural Gas Line		517		312		205		—	—
Insurance Obligations		170		170		—		—	—
Office and Equipment Leases		9,493		3,751		4,032		537	1,173

Total	$	227,887	$	31,182	$	53,113	$	107,313	36,279

Contractual Obligation	Total		Less Than 1 Year		1-3 Years		3-5 Years

	(in thousands)
Term and revolver loan agreement, principal and interest payments(1)	$	34,995	$	2,091	$	32,904	$	—	—
Purchase money loan		556		278		278
Operating lease payments		141		141		—		—	—

Total	$	35,692	$	2,510	$	33,182	$	—	—


Citigroup		Wells Fargo Securities		J.P. Morgan

	Segment	Year Ended December 31, 2012

		(in thousands)
Union Pacific	Fuel Processing and Distribution	$	144,149
Murphy Oil	Fuel Processing and Distribution		121,178

Total		$	265,327

Name		Position with Emerge GP

Ted W. Beneski	56	Chairman of the Board and Director
Rick Shearer	62	Chief Executive Officer
Warren B. Bonham	50	Vice President and Director
Robert Lane	41	Chief Financial Officer
Kevin Clark	56	Independent Director
Francis Kelly	56	Independent Director
Kevin McCarthy	53	Independent Director
Eliot Kerlin	38	Director
Victor L. Vescovo	47	Director

Name and Principal Position

Rick Shearer	245,456	200,000	—	10,266	(2)	455,722
Chief Executive Officer, SSS
Warren Bonham	149,543	—	116,436	8,643	(3)	274,622
President and Chief Executive Officer, Direct Fuels
Robert Lane	34,462	25,000	—	2,223		61,685
Chief Financial Officer, Emerge GP


Transfer of our general partner interest		Our general partner may transfer all, but not less than all, of its general partner interest in us without a vote of our unitholders to an affiliate or another person in connection with its merger or consolidation with or into, or sale of all or substantially all of its assets to, such person. The approval of a majority of the common units, excluding common units held by our general partner and its affiliates, is required in other circumstances for a transfer of the general partner interest to a third party prior to December 31, 2023. Please read "—Transfer of General Partner Interest" beginning on page 199.
Transfer of ownership interests in our general partner		No approval required at any time. Please read "—Transfer of Ownership Interests in the General Partner" beginning on page 199.

Underwriter		Number of Common Units

Citigroup Global Markets Inc.
Wells Fargo Securities, LLC
J.P. Morgan Securities LLC
Stifel, Nicolaus & Company, Incorporated

Total

		Page

EMERGE ENERGY SERVICES LP
Unaudited Pro Forma Condensed Combined Financial Statements
Introduction			F-3
Unaudited Pro Forma Condensed Combined Balance Sheet as of December 31, 2012			F-4
Unaudited Pro Forma Condensed Combined Statement of Operations for the Year Ended December 31, 2012			F-5
Notes to Unaudited Pro Forma Condensed Combined Financial Statements			F-6
Audited Historical Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm			F-10
Consolidated Balance Sheet as of December 31, 2012			F-11
Consolidated Statement of Operations for the period ended December 31, 2012			F-12
Consolidated Statement of Partners' Equity (Deficit) for the period ended December 31, 2012			F-13
Consolidated Statement of Cash Flows for the period ended December 31, 2012			F-14
Notes to Consolidated Financial Statements			F-15
PREDECESSOR
Unaudited Pro Forma Condensed Combined Financial Statements
Introduction			F-16
Unaudited Pro Forma Condensed Combined Balance Sheet as of December 31, 2012			F-17
Unaudited Pro Forma Condensed Combined Balance Sheet as of December 31, 2011			F-18
Unaudited Pro Forma Condensed Combined Balance Sheet as of December 31, 2010			F-19
Unaudited Pro Forma Condensed Combined Statement of Operations for the Year Ended December 31, 2012			F-20
Unaudited Pro Forma Condensed Combined Statement of Operations for the Year Ended December 31, 2011			F-21
Unaudited Pro Forma Condensed Combined Statement of Operations for the Year Ended December 31, 2010			F-22
Notes to Unaudited Pro Forma Condensed Combined Financial Statements			F-23
Historical Financial Statements of Superior Silica Holdings LLC
Audited Consolidated Financial Statements as of December 31, 2012 and 2011 and for the Years Ended December 31, 2012 and 2011:
Report of Independent Registered Public Accounting Firm			F-24
Condensed Consolidated Balance Sheets			F-25
Condensed Consolidated Statements of Operations			F-27
Condensed Consolidated Statements of Members' Deficit			F-28
Condensed Consolidated Statements of Cash Flows			F-29
Notes to Unaudited Condensed Consolidated Financial Statements			F-30
Audited Consolidated Financial Statements as of December 31, 2011 and 2010 and for the Years Ended December 31, 2011 and 2010:
Consolidated Balance Sheets			F-48
Consolidated Statements of Operations			F-50
Consolidated Statements of Members' Deficit			F-51
Consolidated Statements of Cash Flows			F-52
Notes to Consolidated Financial Statements			F-53

		Page

Historical Financial Statements of AEC Holdings LLC
Audited Consolidated Financial Statements as of December 31, 2012 and 2011 and for the Years Ended December 31, 2012 and 2011:
Report of Independent Registered Public Accounting Firm			F-69
Condensed Consolidated Balance Sheets			F-70
Condensed Consolidated Statements of Operations			F-72
Condensed Consolidated Statements of Members' Equity			F-73
Condensed Consolidated Statements of Cash Flows			F-74
Notes to Condensed Consolidated Financial Statements			F-75
Audited Consolidated Financial Statements as of December 31, 2011 and 2010 and for the Years Ended December 31, 2011 and 2010:
Consolidated Balance Sheets			F-95
Consolidated Statements of Operations			F-97
Consolidated Statements of Members' Equity			F-98
Consolidated Statements of Cash Flows			F-99
Notes to Consolidated Financial Statements			F-100
ACQUISITION—DIRECT FUELS FINANCIAL STATEMENTS
Audited Consolidated Financial Statements as of December 31, 2012 and 2011 and for the Years Ended December 31, 2012 and 2011:
Report of Independent Registered Public Accounting Firm			F-121
Condensed Consolidated Balance Sheets			F-122
Condensed Consolidated Statements of Operations			F-124
Condensed Consolidated Statements of Partners' Equity			F-125
Condensed Consolidated Statements of Cash Flows			F-126
Notes to Condensed Consolidated Financial Statements			F-127
Audited Historical Consolidated Financial Statements as of December 31, 2011 and 2010 and for the Years Ended December 31, 2011 and 2010
Consolidated Balance Sheets			F-140
Consolidated Statements of Operations			F-142
Consolidated Statements of Partners' Equity			F-143
Consolidated Statements of Cash Flows			F-144
Notes to Consolidated Financial Statements			F-145

	Fair Value December 31, 2012

Land and improvements	$	1,987
Buildings		788
Equipment		15,852

Total purchase price allocation	$	18,627

	Fair Value December 31, 2012

Supply contracts	$	3,183
Non-compete agreement		1,340
Other		292

Total purchase price allocation	$	4,815

	Fair Value December 31, 2012

Purchase price allocation:
Total purchase price	$	111,813
Current assets and liabilities, net		12,883
Property, plant and equipment		18,627
Intangible assets		4,815
Goodwill		74,684
Non-current assets and liabilities, net		804

Total purchase price allocation	$	111,813


Assets
Cash	$	2,000

Total assets		2,000

Liabilities and Partners' Equity (Deficit)
Related party payable	$	81,673

Total liabilities		81,673

Partners' Equity (Deficit)
General partner		(1,593	)
Limited partner		(78,080	)

Total partners' equity (deficit)		(79,673	)

Total liabilities and partners' equity (deficit)	$	2,000


Revenue	$	—

Total revenue		—

Operating expenses
Compensation expense		81,673

Total expense		81,673

Operating loss		(81,673	)

Net loss	$	(81,673	)

	Partnership Interest		Accumulated Deficit			Total

General partner	$	40	$	(1,633	)	$	(1,593	)
Limited partner		1,960		(80,040	)		(78,080	)

Balance at December 31, 2012	$	2,000	$	(81,673	)	$	(79,673	)


Cash Flows from Operating Activities
Net loss	$	(81,673	)
Changes in operating assets and liabilities:
Related party payable		81,673

Net cash provided by operating activities		—

Cash Flows from Financing Activity
Equity contribution		2,000

Net cash provided by financing activities		2,000

Increase (decrease) in cash		—
Cash, beginning of period		—

Cash, end of period	$	2,000

					Fair Value Measurement

	Carrying Amount				Level 2				Level 3				Total
	2012		2011		2012		2011		2012		2011		2012		2011
Long-term debt, including current portion	$	104,708,440	$	58,674,614	$	110,189,670	$	67,394,595	$	—	$	—	$	110,189,670	$	67,394,595

		Useful Lives

Building and land improvements including assets under capital lease		10 - 20 years
Railroad line and related improvements		15 - 40 years
Plant equipment including assets under capital lease		5 - 7 years
Industrial vehicles		7 years
Furniture and office equipment		3 years

Years Ended December 31,	2012			2011

Interest cost related to financing activities, net	$	10,811,066		$	2,121,403
Loss on early extinguishment of long-term debt		377,063
Amortization of deferred financing costs		640,851			212,852
Amortization of debt discounts		92,304			92,308
Capitalized interest costs		(1,033,532	)		(224,493	)
Accretion of restructured long-term debt (refer to Note 5)		(267,841	)		(367,327	)

Total interest expense	$	10,619,911		$	1,834,743

Years Ended December 31,	2012		2011

Beginning balance	$	431,646	$	48,328
Additions		258,000		383,318
Accretion		—		—

Total asset retirement obligations	$	689,646	$	431,646

December 31,	2012		2011

Raw materials	$	8,317,462	$	1,947,247
Work in process		1,597,557		478,669
Finished goods		700,091		192,943

	$	10,615,110	$	2,618,859

Years ending December 31,

2013	$	8,482,367
2014		10,205,335
2015		10,000,000
2016		28,749,099
2017		47,181,029
Thereafter		—

Total		104,617,830
Unaccreted restructured long-term debt		321,383
Unamortized debt discount		(230,773	)

Balance	$	104,708,440