S-1 1 a2213394zs-1.htm S-1

Use these links to rapidly review the document
TABLE OF CONTENTS
INDEX TO FINANCIAL STATEMENTS

Table of Contents

As filed with the Securities and Exchange Commission on March 22, 2013

Registration No. 333-

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

Form S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933

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

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

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

         If any of the securities being registered on this form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. o

         If this form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

         If this form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering o

         If this form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

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

Large accelerated filer o   Accelerated filer o   Non-accelerated filer ý
(Do not check if a smaller
reporting company)
  Smaller reporting company o

CALCULATION OF REGISTRATION FEE

       
 
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

 

(1)
Includes common units issuable upon exercise of the underwriters' option to purchase additional common units.

(2)
Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o).

         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.


Table of Contents

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.

SUBJECT TO COMPLETION, DATED MARCH 22, 2013

PRELIMINARY   PROSPECTUS

LOGO

Emerge Energy Services LP

Common Units
Representing Limited Partner Interests



           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.

           These risks include the following:

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

    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 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.

    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.

    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.

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

    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.

    Our tax treatment depends on our status as a partnership for federal income tax purposes. If the Internal Revenue Service 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.

    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.



           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.



 
  Per Common Unit   Total
Public Offering Price   $   $
Underwriting Discount(1)   $   $
Proceeds to Emerge Energy Services LP (before expenses)   $   $

(1)
Excludes a structuring fee of        % of the gross offering proceeds from this offering payable to Citigroup Global Markets Inc. See "Underwriting" beginning on page 228 of this prospectus.

           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.



Citigroup   Wells Fargo Securities   J.P. Morgan



Stifel

   

                        , 2013


Table of Contents

[GRAPHIC]


Table of Contents


TABLE OF CONTENTS

 
  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  

i


Table of Contents

 
  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  

ii


Table of Contents

 
  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
 

iii


Table of Contents

iv


Table of Contents

        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.


Industry and Market Data

        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.


Certain Definitions

        As the context requires, references in this prospectus to:

    "SSS" refers to Superior Silica Holdings LLC, or SSH, with respect to financial information, and to SSH's subsidiary Superior Silica Sands LLC, which will be contributed to us upon the consummation of this offering, with respect to operational information;

    "AEC" refers to AEC Holdings LLC, or AEC Holdings, with respect to financial information, and to AEC Holdings' subsidiary Allied Energy Company LLC, which will be contributed to us upon the consummation of this offering, with respect to operational information; and

    "Direct Fuels" refers to Direct Fuels Partners, L.P., or DF Parent, with respect to financial information, and to Insight Equity Acquisition Partners, LP, a wholly owned subsidiary of DF Parent that will be contributed to us upon the consummation of this offering, with respect to operational 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.

v


Table of Contents


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

 

1


Table of Contents

    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

CHART

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

 

2


Table of Contents

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.

 

3


Table of Contents

        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)
  Primary
Reserve
Composition
  Depth of
Reserves
  Lease
Expiration
Date
  Mine
Area
  Wet Plant
Capacity
(Tons)
  Dry Plant
Capacity
(Tons)
  On-site Rail
Infrastructure
  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.

        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

 

4


Table of Contents

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.

 

5


Table of Contents


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
  Transmix
Processing
Capacity
(Gal./Year)
  Fuel From
Transmix
Sold—Total
(Gal./Year)
  Wholesale
Fuel
Volume
Sold—Total
(Gal./Year)
  Terminal
Tankage
Capacity
(Gal.)
  Biodiesel
Refining
Capacity
(Gal./Year)
 
 
  (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

 

6


Table of Contents

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,

 

7


Table of Contents

      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.

 

8


Table of Contents


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.

 

9


Table of Contents

    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

 

10


Table of Contents

      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.

 

11


Table of Contents


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.

 

12


Table of Contents

    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.


Tax Risks to Common Unitholders

    Our tax treatment depends on our status as a partnership for federal income tax purposes. If the Internal Revenue Service (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.

    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.

    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.

 

13


Table of Contents


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.

 

14


Table of Contents


Organizational Structure After the Offering

        The following diagram depicts our organizational structure and ownership after giving effect to this offering and the related offering-related transactions.

Public Common Units(1)

      %(2)

Common Units held by Insight Equity and other private investors

      %(2)

General Partner Units

      %
       

Total

    100.0 %
       

(1)
Common units to be awarded at the closing of this offering pursuant to the 2013 Long-Term Incentive Plan.

(2)
Assumes the underwriters do not exercise their option to purchase additional common units.

 

15


Table of Contents

CHART

 

16


Table of Contents


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.

 

17


Table of Contents

        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.

 

18


Table of Contents


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.

 

19


Table of Contents

    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.

 

20


Table of Contents

    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.

 

21


Table of Contents

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."

 

22


Table of Contents


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

 

23


Table of Contents

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    
 
 
  Pro Forma
Emerge Energy Services
 
 
  SSS   AEC  
 
  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.

 

24


Table of Contents

(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    
 
 
  Pro Forma
Emerge Energy Services
 
 
  SSS   AEC  
 
  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.

 

25


Table of Contents


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

        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. Adjusted EBITDA is used as a supplemental financial measure by our management and external users of our financial statements, such as investors and commercial banks, to assess:

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

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

    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.

        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

 

26


Table of Contents

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    
 
 
  Pro Forma
Emerge Energy
Services
 
 
  SSS   AEC  
 
  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.

 

27


Table of Contents


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  
                               

 

28


Table of Contents


RISK FACTORS

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


Risks Related to Our Business

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

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

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

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

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

    the level of competition from other companies;

    the cost and time required to execute organic growth opportunities;

    difficulty collecting receivables; and

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

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

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

    the level of our operating costs and expenses;

    our debt service requirements and other liabilities;

    fluctuations in our working capital needs;

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

    the cost of acquisitions, if any;

    fluctuations in interest rates;

    our ability to borrow funds and access capital markets; and

29


Table of Contents

    the amount of cash reserves established by our general partner.

        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.

30


Table of Contents

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:

    changes in the price and availability of transportation;

    inability to obtain necessary production equipment or replacement parts;

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

    unusual or unexpected geological formations or pressures;

31


Table of Contents

    unanticipated ground, grade or water conditions;

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

    labor disputes and disputes with our excavation contractors;

    late delivery of supplies;

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

    technical difficulties or failures;

    cave-ins or similar pit wall failures;

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

    industrial accidents;

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

    inability of our customers or distribution partners to take delivery;

    reduction in the amount of water available for processing;

    fires, explosions or other accidents; and

    facility shutdowns in response to environmental regulatory actions.

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

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

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

32


Table of Contents

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

33


Table of Contents

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.

34


Table of Contents

        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

35


Table of Contents

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

36


Table of Contents

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.

37


Table of Contents

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:

    develop new business and enter into contracts with new customers;

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

    identify and obtain additional frac sand reserves;

    recruit and train qualified personnel and retain valued employees;

    expand our geographic presence;

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

    consummate accretive acquisitions;

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

    meet customer-specific contract requirements or pre-qualifications;

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

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

        If we do not achieve 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

38


Table of Contents

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

39


Table of Contents

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

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

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

        Our ability to service our debt 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:

    grant liens;

    incur additional indebtedness;

    engage in a merger, consolidation or dissolution;

    enter into transactions with affiliates;

40


Table of Contents

    sell or otherwise dispose of assets, businesses and operations;

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

    make acquisitions, investments and capital expenditures.

        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.

41


Table of Contents

        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:

    in connection with the audit of the consolidated financial statements of SSS for the year ended December 31, 2010 and again in connection with the audit of the financial statements of SSS for the year ended December 31, 2011, SSH's management identified a material weakness relating to the failure to record certain entries and adjustments during the year-end closing process; and

    in connection with the audit of the consolidated financial statements of AEC for the year ended December 31, 2010, AEC Holdings' management identified a material weakness relating to access to and security controls on AEC's inventory and transaction management software.

        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:

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

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

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

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

42


Table of Contents

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

43


Table of Contents

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.

44


Table of Contents

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

45


Table of Contents

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

46


Table of Contents

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

47


Table of Contents

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.

48


Table of Contents

        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.


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.

        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.

49


Table of Contents

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:

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

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

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

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

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

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

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

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

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

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

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

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

50


Table of Contents

        Please read "Conflicts of Interest and Duties" beginning on page 180.

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:

    how to allocate business opportunities among us and its affiliates;

    whether to exercise its limited call right;

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

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

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

        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.

51


Table of Contents

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

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

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

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

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

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

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

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

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

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

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

52


Table of Contents

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:

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

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

    the ratio of taxable income to distributions may increase;

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

53


Table of Contents

    the market price of the common units may decline.

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:

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

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

        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

54


Table of Contents

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:

    our quarterly distributions;

    our quarterly or annual earnings or those of other companies in our industry;

    announcements by us or our competitors of significant contracts or acquisitions;

    changes in accounting standards, policies, guidance, interpretations or principles;

    general economic conditions;

    the failure of securities analysts to cover our common units after this offering or changes in financial estimates by analysts;

    future sales of our common units; and

    other factors described in these "Risk Factors."

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.


Tax Risks to Common Unitholders

        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.

55


Table of Contents

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.

56


Table of Contents

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

57


Table of Contents

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

58


Table of Contents

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.

59


Table of Contents


USE OF PROCEEDS

        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:

    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.

        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.


New Credit Facility

        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

60


Table of Contents

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.


Existing Debt Arrangements

    As of December 31, 2012, the retirement value of SSS's total bank indebtedness was $103.9 million, consisting of:

    $48.5 million borrowed under its term loan facility and $8.3 million borrowed under its revolving credit facility, each of which bears interest at LIBOR plus 375 basis points and matures in September 2016;

    $41.8 million outstanding under its second lien term loan which bears interest at 18% per year (of which 6% is payable in kind) and matures in March 2017; and

    $5.3 million outstanding under its third lien term loan maturing in September 2017 and bearing interest at 0% per year.

    As of December 31, 2012, AEC Holdings had approximately $18.4 million and $13.0 million outstanding under its term loan facility and revolving credit facility, respectively, with a weighted average interest rate of 4.8%. Both of these facilities mature on April 1, 2015. Additionally, AEC carries a $2.4 million troubled debt restructuring liability related to the term loan which is non-cash, carries no interest and amortizes over the life of the loan. Borrowings made under AEC Holdings' revolving credit facility within the last twelve months were used primarily to fund capital expenditures and operating working capital requirements.

    As of December 31, 2012, Direct Fuels had approximately $16.7 million of indebtedness outstanding under its term loan with an average interest rate of 4.21% and approximately $0.4 million of indebtedness outstanding under its revolving credit facility with an average interest rate of 4.75%. Prior to the closing of this offering, Direct Fuels expects to incur $7.4 million of additional indebtedness that will be used to redeem all of its outstanding preferred units. Direct Fuels' term loan and revolving credit facilities mature on November 28, 2013. Borrowings made under Direct Fuels' credit facility within the last twelve months were used primarily to fund distributions to its equity owners.

        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."


Sensitivity in Offering Size

        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

61


Table of Contents

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.


Certain Affiliations

        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.

62


Table of Contents


CAPITALIZATION

        The following table shows:

    the pro forma combined cash and capitalization of SSS and AEC, which together constitute our predecessor for accounting purposes, as of December 31, 2012;

    our pro forma cash and capitalization as of December 31, 2012, which consists of the pro forma combined cash and capitalization of SSS and AEC as of December 31, 2012, giving effect to the acquisition of Direct Fuels, the redemption of the Direct Fuels preferred units and adjustment to fair value as of such date; and

    our pro forma as adjusted cash and capitalization as of December 31, 2012, giving effect to:

    the transactions described in "Summary—Partnership Structure and Offering-Related Transactions"; and

    the receipt and use of net proceeds of $             million from this offering and our anticipated new revolving credit facility in the manner described in "Use of Proceeds."

        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.

 
  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   $    
               

(1)
We will use a portion of the net proceeds from this offering to repay indebtedness outstanding under the credit facilities of SSS, AEC Holdings and Direct Fuels. As of                                    , 2013, there was an aggregate $             million outstanding under such credit facilities. Additionally, we assume that prior to the offering, Direct Fuels will have borrowed $7.4 million to fund redemption of the preferred units.

(2)
Reflects our borrowing of approximately $             million under our anticipated new revolving credit facility, which will be used 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.

        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.

63


Table of Contents


DILUTION

        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:

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)

        $    
             

(1)
Determined by dividing the number of common units to be issued to Insight Equity and its affiliates in connection with this offering into the pro forma net tangible book value of the contributed interests.

(2)
Determined by dividing the total number of common units to be outstanding after this offering into our pro forma net tangible book value.

(3)
For each increase or decrease in the initial public offering price of $1.00 per common unit, dilution in net tangible book value per common unit would increase or decrease by $            per common unit.

(4)
Because the total number of units outstanding following this offering will not be impacted by any exercise of the underwriters' option to purchase additional common units and any net proceeds from such exercise will not be retained by us, there will be no change to the dilution in net tangible book value per common unit to purchasers in this offering due to any such exercise of the option.

64


Table of Contents

        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:

 
  Units Acquired   Total
Consideration
 
 
  Number   Percent   Amount   Percent  

General partner and affiliates(1)(2)(3)

            % $         %

Public common unitholders

            % $         %
                   

Total

          100.0 % $       100.0 %
                   

(1)
The units held by our general partner and its affiliates consist of                        common units and                                    general partner units.

(2)
Assumes the underwriters' option to purchase additional common units is not exercised.

(3)
In accordance with GAAP, the assets contributed by SSH and AEC Holdings were recorded at historical cost and the assets contributed by DF Parent were recorded at fair value. Book value of the consideration provided by SSH, AEC Holdings and DF Parent, as of December 31, 2012, after giving effect to the offering-related transactions was as follows:

   
  (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

  $    
         

65


Table of Contents


OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

        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.


General

        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:

    Our unitholders have no contractual or other legal right to receive cash distributions from us on a quarterly or other basis. The board of directors of our general partner will adopt a policy pursuant to which we will distribute to our unitholders each quarter all of the available cash we generate each quarter, as determined quarterly by the board of directors, but it may change this policy at any time.

    Our ability to make cash distributions pursuant to our cash distribution policy will be subject to our compliance with our credit facility, which contain financial tests and covenants that we must satisfy. Should we be unable to satisfy these financial covenants or if we are otherwise in default under our credit facility, we will be prohibited from making cash distributions to you notwithstanding our stated cash distribution policy.

66


Table of Contents

    Our business performance and 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 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. Furthermore, none of our limited partnership interests, including those held by Insight Equity and our other private investors, will be subordinate in right of distribution payment to the common units sold in this offering.

    Our general partner will have the authority to establish cash reserves for the prudent conduct of our business, and the establishment of or increase in those reserves could result in a reduction in cash distributions to our unitholders. Our partnership agreement does not set a limit on the amount of cash reserves that our general partner may establish. Any decision to establish cash reserves made by our general partner in good faith will be binding on our unitholders.

    Prior to making any distributions on our units, we will reimburse our general partner and its affiliates for all direct and indirect expenses they incur on our behalf. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us, but does not limit the amount of expenses for which our general partner and its affiliates may be reimbursed. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates will reduce the amount of cash to pay distributions to our unitholders.

    Under Section 17-607 of the Delaware Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets.

    We may lack sufficient cash to make distributions to our unitholders due to a number of factors that would adversely affect us, including but not limited to decreases in net sales or increases in operating expenses, principal and interest payments on debt, working capital requirements, capital expenditures or anticipated cash needs. See "Risk Factors" for information regarding these factors.

        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 generally distribute a significant percentage of our cash from operations to our unitholders on a quarterly basis, after, among other things, the establishment of cash reserves and payment of our expenses. Therefore, our growth, if any, may not be comparable to those businesses that reinvest most or all of their cash to expand ongoing operations. Moreover, any future growth may be slower than our historical growth. We expect that we will rely upon external financing sources in large part, including bank borrowings and issuances of debt and equity interests, to fund our expansion capital expenditures. To the extent we are unable to finance growth externally, our distribution policy could significantly impair our ability to grow.

        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.

67


Table of Contents


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.

68


Table of Contents


Unaudited Pro Forma Cash Available for Distribution

 
  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

  $    

(1)
For the year ended December 31, 2012, AEC incurred a $0.8 million litigation settlement expense, offset by $0.2 million of other income at SSS and Direct Fuels.

(2)
Reflects estimated 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 liability insurance costs; and outside director compensation.

(3)
Cash interest expense consists of actual, historical cash interest expenditures and does not reflect the capital structure under our anticipated new credit facility.

(4)
Certain customers prepaid for future sand deliveries to fund a portion of our New Auburn facility construction costs. As we sell sand to these customers, we recognize a reduction of customer prepaid sale liabilities through non-cash revenues. Because this portion of our revenues is non-cash, we have deducted the customer advance liability payments from our Pro Forma Adjusted EBITDA in computing our Pro Forma Cash Available for Distribution. As of December 31, 2012, we have $4.0 million of customer advance liabilities. We expect these obligations to be fully satisfied by October 2013 and assume that we would have borrowed amounts equivalent to such expected non-cash revenues during the historical periods presented. Accordingly, we have added back such amounts in determining our estimated Pro Forma Cash Available for Distribution for the historical periods presented.

(5)
Represents capital lease principal payments to Fred Weber, Inc., which we deduct from our Pro Forma Adjusted EBITDA in computing our Pro Forma Cash Available for Distribution for the backcast period. We assume that we would have satisfied such payments through borrowings under our revolving credit facility during the historical periods presented. Accordingly, we have added back such amounts in determining our estimated Pro Forma Cash Available for Distribution for the historical periods presented.

(6)
Maintenance capital expenditures are capital expenditures required to maintain, over the long term, our asset base, operating income or operating capacity.

(7)
Growth capital expenditures are capital expenditures made to increase, over the long term, our asset base, operating income or operating capacity.

(8)
Includes distributions on common units awarded pursuant to the 2012 Long-Term Incentive Plan at the closing of this offering.

69


Table of Contents


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.

70


Table of Contents


Estimated Cash Available for Distribution

 
  Three Months Ending   Twelve
Months
Ending
March 31,
2014
 
 
  June 30,
2013
  September 30,
2013
  December 31,
2013
  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.

71


Table of Contents

(5)
A portion of the cost we pay to Fred Weber to process sand at our wet plant is recorded as cost of goods sold and a portion is recorded as a capital lease payment. The capital lease principal payments have been deducted from our Adjusted EBITDA in computing our cash available for distribution for the forecast period. We have assumed that we will satisfy such payments through borrowings under our revolving credit facility 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.

(6)
Maintenance capital expenditures are capital expenditures required to maintain, over the long term, our asset base, operating income or operating capacity.

(7)
Growth capital expenditures are capital expenditures made to increase, over the long term, our asset base, operating income or operating capacity.


Assumptions and General Considerations

        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:

    Sand.  We estimate that our Sand revenues for the twelve months ending March 31, 2014 will be $142.8 million, compared to $66.7 million for the year ended December 31, 2012. This increase

72


Table of Contents

      is primarily attributable to the increased production volume resulting from the operation of our Barron County facility. More specifically, our New Auburn sales are expected to be approximately 1,012,000 tons during the twelve months ending March 31, 2014 compared to approximately 1,061,000 tons during the year ended December 31, 2012 and 1,191,724 tons on an annualized run-rate basis for the last half of 2012. Of the 1,012,000 tons forecasted to be sold from our New Auburn plant in the twelve months ending March 31, 2014, approximately 74% are forecasted to be sold pursuant to take-or-pay contracts. The remaining forecasted New Auburn plant sales volumes are expected to be sold pursuant to fixed-volume sales contracts with other customers, purchases from our take-or-pay customers in excess of their contractual obligations or in the spot market. Our forecasted New Auburn sales volume for the twelve months ending March 31, 2014 is less than our annualized run rate sales volume for the last half of 2012 because our run rate sales include spot sales to recurring spot customers with whom we have since commenced contract discussions in addition to sales to our current contract customers who regularly purchased frac sand quantities in excess of their contractual volume. Forecasted sales volumes from our Barron County plant are 987,000 tons for the twelve months ending March 31, 2014, consisting of 506,000 tons of volume sold from our facilities, and 481,000 tons of volume sold from locations near our customers' drilling sites. We have contracted approximately 21% of this volume through long-term take-or-pay and fixed-volume contracts and have contracted approximately an additional 20% through efforts-based sales contracts. These totals do not include any efforts-based volumes under our long-term tolling agreement with Midwest Frac. We expect the majority of our non-contract sales to be sold from sites near our customers' end drilling locations. In order to support these sales, we have established distribution centers at locations in northwestern Canada and northeastern United States shale plays. We believe this will enable us to broaden our customer base and, in some cases, we have already been able to secure multi-month purchase orders to support this anticipated sales volume. We have assumed prices for the frac sand sold pursuant to customer agreements based on the prices set forth in our existing agreements, which results in an average price of $52.89 per contracted ton for our Wisconsin facilities. We expect the average price for frac sand from our Wisconsin facilities sold on the spot market will be $55.86 per ton (before accounting for transportation revenue on tons sold from distribution sites within shale plays) for the twelve months ending March 31, 2014, which is 10% less than the average price we received from our customers who had take-or-pay agreements with us in the second half of 2012.

    Fuel Processing and Distribution.  We estimate that our Fuel Processing and Distribution revenues for the twelve months ending March 31, 2014 will be $883.6 million, compared to $890.2 million for the year ended December 31, 2012. This decrease is primarily attributable to projected increases in the volumes of wholesale fuel sold offset by fuel price decreases. We expect our average selling price per gallon to decrease by approximately 2% from $3.11 in 2012 to $3.03 for the twelve months ending March 31, 2014. We expect our refined product volume to increase by approximately 2% compared to the year ended December 31, 2012 as a result of higher transmix volumes in the Dallas-Fort Worth and Birmingham markets.

        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:

    Sand.  Our Sand cost of goods sold consists of labor expenses, utility and fuel costs, repairs and maintenance expenses, and health, safety and environmental related costs, among others. We estimate that our cost of goods sold will be $77.2 million for the twelve months ending

73


Table of Contents

      March 31, 2014, compared to $27.4 million for the year ended December 31, 2012. A small portion of the cost increase is expected to result from contractual price increases in our vendor contracts and our assumption that non-contracted costs will rise in line with historical inflation averages. The majority of the increase is attributable to the increase in forecasted sales volume and the approximately 481,000 tons of frac sand that management anticipates selling from locations in shale plays close to our customers' drilling locations. For such sales, we must bear the cost of transporting product to a storage location in the shale play. In return, the customer will pay us a fee intended to reimburse us for our transportation costs and to compensate us for the supply chain services provided.

    Fuel Processing and Distribution.  Our Fuel Processing and Distribution cost of goods sold consists primarily of the cost of fuel, but also contains labor expense, various operating expenses as well as the cost of inbound freight. We estimate that our cost of goods sold will be approximately $856.1 million for the twelve months ending March 31, 2014, compared to approximately $863.2 million for the year ended December 31, 2012. This decrease is primarily attributable to a projected decrease in the cost of fuel offset by higher fuel volumes. Our cost per gallon sold is forecast to decrease from $2.99 to $2.91 per gallon.

        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:

    Sand.  We estimate that our Sand selling, general and administrative expenses will be $7.4 million for the twelve months ending March 31, 2014, compared to $5.5 million for the year ended December 31, 2012. Projected increases in selling, general and administrative expenses are largely attributable to higher expenses that we will incur as a result of additional finance, engineering and logistics personnel that have been hired to support our Barron County facility. We believe we will be able to capitalize on our current scale and existing infrastructure to improve margins with incremental growth, and we do not expect our selling, general and administrative expenses to increase proportionately, beyond the above noted expenses, as we expand production at our Barron County facility. We expect the cost structure of our Barron and New Auburn facilities to be roughly equivalent.

    Fuel Processing and Distribution.  We estimate that Fuel Processing and Distribution selling, general and administrative expenses will be approximately $7.3 million for the twelve months ending March 31, 2014, compared to approximately $8.5 million for the year ended December 31, 2012. This projected decrease of $1.2 million in estimated selling, general and administrative expense is primarily attributable to lower professional fees for the twelve months ending March 31, 2014.

        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

74


Table of Contents

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:

    Sand.  We estimate that our Sand depreciation, depletion and amortization expense will be $10.1 million for the twelve months ending March 31, 2014, compared to $6.4 million for the year ended December 31, 2012. The expected increase is attributable to the completion of our Barron County facility in December 2012. Estimated depreciation expense is computed over the estimated useful lives of our fixed assets, which are based on consistent average depreciable asset lives and methodologies. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates—Depreciation Methods and Estimated Useful Lives of Property, Plant and Equipment and Depletion" beginning on page 119.

    Fuel Processing and Distribution.  We estimate that our Fuel Processing and Distribution depreciation and amortization expense will be approximately $7.9 million for the twelve months ending March 31, 2014, compared to $5.5 million for the year ended December 31, 2012. Depreciation expense is expected to increase due to the addition of two new storage tanks at our Dallas-Fort Worth facility and a vapor recovery system at our Birmingham, Alabama facility during 2012, as well as the impact of the step up in value of Direct Fuels' assets. This will be partially offset by the fact that certain assets will become fully depreciated in 2013.

        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:

    Sand.  We estimate that our Sand growth capital expenditures and maintenance capital expenditures will be $3.8 million and $1.7 million, respectively, for the twelve months ending March 31, 2014, compared to $37.8 million and $1.2 million, respectively, for the year ended December 31, 2012. Growth capital expenditures beyond our forecast period are anticipated to support incremental infrastructure expansions that will improve our production planning and logistics capabilities and that will further position us to capitalize upon growth opportunities we anticipate will develop within our current customer portfolio. After the closing of this offering, we expect to fund growth capital expenditures with funds generated from our operations, borrowings under our anticipated new revolving credit facility and the issuance of additional common units and debt. For purposes of this forecast, we have assumed that we will fund all of the forecasted growth capital expenditures with borrowings under our anticipated new revolving credit facility.

      The majority of our maintenance capital expenditures will be spent on the replacement and refurbishment of wet plant and dry plant equipment that becomes damaged due to the naturally abrasive qualities of the sand we process.

75


Table of Contents

    Fuel Processing and Distribution.  We estimate that our Fuel Processing and Distribution growth capital expenditures and maintenance capital expenditures will be $0.1 million and $0.9 million, respectively, for the twelve months ending March 31, 2014, compared to $1.0 million and $1.8 million, respectively, for the year ended December 31, 2012. Capital expenditures were higher in the year ended December 31, 2012 as a result of a one-time growth capital expenditure related to AEC's vapor recovery unit and truck fuel loading rack upgrades. We expect to fund maintenance capital expenditures from cash generated by our operations.

        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:

    There will not be any new federal, state or local regulation of the portions of the energy industry in which we operate, or a new interpretation of existing regulation, that will be materially adverse to our business.

    There will not be any major adverse change in our business, in the portions of the energy industry that we serve, or in general economic conditions, including in the levels of crude oil and natural gas production and demand in the geographic areas that we serve.

    There will not be any material accidents, weather-related incidents, unscheduled downtime or similar unanticipated events with respect to our facilities or those of third parties on which we depend.

    Although we may undertake projects where opportunities arise, for the purposes of this forecast no acquisitions or other significant growth capital expenditures are reflected (other than as described above).

    Market, insurance and overall economic conditions will not change substantially.

    Our customers subject to take-or-pay and fixed-volume commitments will fully perform under their contractual arrangements with us.

        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.

76


Table of Contents


PROVISIONS OF OUR PARTNERSHIP AGREEMENT RELATING TO CASH DISTRIBUTIONS

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


Distributions of Available Cash

        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.

77


Table of Contents

SELECTED 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 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.

78


Table of Contents

Selected Predecessor Historical Financial and Operating Data

 
  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  
                           

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

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

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

79


Table of Contents

 
  Predecessor Historical  
 
  SSS   AEC  
 
  Year Ended
December 31,
  Year Ended
December 31,
 
 
  2010   2011   2012   2010   2011   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              

Average price (per ton)(1)

  $ 93.05   $ 73.77   $ 54.56              

Average production cost (per ton)(2)            

  $ 98.92   $ 50.55   $ 22.41              

Fuel Processing and Distribution segment:

                                     

Fuel Distribution (gallons)

                102,375     111,172     176,451  

Throughput (gallons)

                364,007     358,706     352,585  

(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.

80


Table of Contents

Selected Historical and Pro Forma Financial and Operating Data

 
  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