Table of Contents

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2013

OR

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

For the transition period from                   to                   

Commission file number 001-35912

EMERGE ENERGY SERVICES LP

(Exact name of registrant as specified in its charter)

1400 Civic Place, Suite 250
Southlake, Texas 76092
(Address of principal executive offices) (Zip Code)

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

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

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). YES o   NO x

At May 31, 2013, there were 23,219,680 common units outstanding.

Table of Contents

Explanatory Note

The information contained in this report relates to periods that ended prior to the closing of the initial public offering (“IPO”) of Emerge Energy Services LP (the “Partnership”), and prior to the effective dates of certain of the agreements discussed herein.  Consequently, the unaudited condensed combined financial statements and related discussion of financial condition and results of operations contained in this report pertain to Superior Silica Holdings LLC and AEC Holdings LLC (combined, the “Predecessor”), each of which was contributed to the Partnership in connection with the completion of the IPO.

The unaudited condensed combined financial statements for the Predecessor have been derived from the unaudited condensed consolidated financial statements of Superior Silica Holdings LLC (“SSH”) and AEC Holdings LLC (“AEC Holdings”).  The unaudited condensed combined financial statements should be read in conjunction with the accompanying notes and with the historical consolidated financial statements and related notes set forth in earlier public filings.

The Partnership has owned and operated the businesses of the Predecessor since the closing of the Partnership’s initial public offering on May 14, 2013.  The contribution of the Predecessor’s business to the Partnership will be recognized for accounting purposes at its historical carryover basis as it is considered a reorganization of entities under common control.

The unaudited condensed combined financial statements may not be indicative of the results that actually would have occurred if the Partnership had assumed the operations of the Predecessor on the dates indicated or that would be obtained in the future.

1

Table of Contents

TABLE OF CONTENTS

2

Table of Contents

PART I                        FINANCIAL INFORMATION

Item 1.                            Financial Statements

SUPERIOR SILICA HOLDINGS LLC AND AEC HOLDINGS LLC (PREDECESSOR)

UNAUDITED CONDENSED COMBINED BALANCE SHEETS

(in thousands)

See accompanying notes to unaudited condensed combined financial statements.

3

Table of Contents

SUPERIOR SILICA HOLDINGS LLC AND AEC HOLDINGS LLC (PREDECESSOR)

UNAUDITED CONDENSED COMBINED STATEMENTS OF OPERATIONS

(in thousands)

See accompanying notes to unaudited condensed combined financial statements.

4

Table of Contents

SUPERIOR SILICA HOLDINGS LLC AND AEC HOLDINGS LLC (PREDECESSOR)

UNAUDITED PRO FORMA CONDENSED COMBINED STATEMENT OF MEMBERS’ EQUITY

(in thousands)

See accompanying notes to unaudited condensed combined financial statements.

5

Table of Contents

SUPERIOR SILICA HOLDINGS LLC AND AEC HOLDINGS LLC (PREDECESSOR)

UNAUDITED CONDENSED COMBINED STATEMENTS OF CASH FLOWS

(in thousands)

See accompanying notes to unaudited condensed combined financial statements.

6

Table of Contents

SUPERIOR SILICA HOLDINGS LLC AND AEC HOLDINGS LLC (PREDECESSOR)

NOTES TO UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS

(schedule dollars in thousand only, except unit and per unit amounts)

1.              ORGANIZATION AND BASIS OF PRESENTATION

Organization

Sand Segment. Superior Silica Holdings LLC, or SSH, operates the Sand segment. The Sand segment produces and sells various grades of sand primarily used in the extraction of oil and natural gas and the production of numerous building products and foundry materials. Our industrial sand processing facilities are located in New Auburn, Wisconsin, Barron, Wisconsin and Kosse, Texas.

Fuel Segment. AEC Holdings operates the Fuel processing and distribution (“Fuel”) segment. The Fuel segment operates a motor fuel bulk storage facility located in Birmingham, Alabama, which purchases, blends, markets, and transports light petroleum products to its customers in the Birmingham area. We also operate a transportation mixture (“transmix”) distillation tower that extracts gasoline and diesel fuel from commingled motor fuels as well as offering terminal cleaning and petroleum reclamation services.

The accompanying unaudited condensed combined financial statements are the responsibility of the management of SSH and AEC Holdings, (combined, the “Predecessor”). The Predecessor eliminates all significant intercompany balances and transactions in the combination of its financial statements.

Basis of Presentation

The unaudited condensed combined financial statements have been derived from the historical consolidated financial statements of the Predecessor for accounting purposes.

SSH and AEC Holdings are under common control of a private equity fund and as a result the historical financial statements of SSH and AEC Holdings are recognized as a combination of entities under common control.

2.              SIGNIFICANT ACCOUNTING POLICIES

The accompanying condensed combined interim financial statements should be read in conjunction with the Emerge Energy Services LP’s prospectus dated May 8, 2013 (the “Prospectus”) included in its Registration Statement on Form S-1, as amended (SEC File No. 333-187487). Certain information and footnote disclosures required by accounting principles generally accepted in the United States of America (“GAAP”) for complete annual consolidated financial statements have been omitted and, therefore, these interim financial statements should be read in conjunction with the SSH and AEC Holdings’ audited consolidated financial statements for the year ended December 31, 2012, which are included in the Prospectus. In the opinion of management, these financial statements, which have been prepared pursuant to the rules of the U.S. Securities and Exchange Commission (“SEC”) and GAAP for interim financial reporting, reflect all adjustments necessary to state fairly the results for the interim periods. The results of operations for the three months ended March 31, 2013 are not necessarily indicative of those for a full year.

Operating results are not necessarily indicative of the results to be expected for the full year or any other interim period, due to the seasonal and weather-related conditions in certain aspects of our business. The unaudited condensed combined financial statements should be read in conjunction with SSH’s and AEC Holdings’ consolidated financial statements and notes thereto.

Revenue Recognition

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

In our Sand segment, revenue is derived by mining and processing minerals that our customers purchase for various uses. Our revenues are primarily a function of the price per ton realized and the volumes sold. In some instances, our revenues also include a charge for transportation services we provide to our customers. Our Sand segment transportation revenue fluctuates based on a number of factors, including the volume of product we transport under contract, service agreements with our customers, the mode of transportation utilized and the distance between our plants and customers.

We sell a limited amount of our Sand segment products under short-term price agreements or at prevailing market rates.  The majority of our Sand segment revenues are realized through take-or-pay supply agreements with large oilfield services companies. Initial terms

7

Table of Contents

of these contracts expire between 2013 and 2021.  These agreements define, among other commitments, the volume of product that our customers must purchase, the volume we must provide and the price that we will charge, as well as the rate that our customers will pay. Prices under these agreements are generally fixed and subject to adjustment, upward or downward, only for certain changes in published producer cost indices or market factors.  As a result, our realized prices may not grow at rates consistent with broader industry pricing.  For example, during periods of rapid price growth, our realized prices may grow more slowly than those of competitors, and during periods of price decline, our realized prices may outperform industry averages. With respect to the take-or-pay arrangements, if the customer is unable to carry forward minimum quantity deficiencies, we recognize Sand segment revenues to the extent of the minimum contracted quantity, assuming payment has been received or is reasonably assured. If deficiencies can be carried forward, receipts in excess of actual sales are recognized as deferred revenues until production is actually taken or the right to carry forward minimum quantities expires.

We invoice the majority of our Sand segment customers on a per shipment basis, although for some larger customers, we consolidate invoices weekly or monthly. Standard terms are net 30 days for the Sand segment and net 10 days for the Fuel segment, although extended terms are offered in competitive situations. The amounts invoiced include the amount charged for the product, transportation costs (if paid by us) and costs for additional services as applicable, such as costs related to transload the product from railcars to trucks for delivery to the customer site.

Sand segment revenues from sales to customers who have advanced payments to us are invoiced to accounts receivable and recognized as revenue at the gross contractual rate per ton.  Subsequently, we recognize a reduction of accounts receivable and a corresponding reduction in the “advances from customers” liability (net of accrued interest) for the contracted repayment rate per ton.

Transportation revenue is reported in revenue and is derived from charging our customers i) to deliver product to their locations, ii) to deliver product to a transload site from which customers are able to take possession, or iii) for leased rail cars used to transport product to the customer’s location. Transportation expense is the cost we pay to ship i) product from our production facilities to customer facilities, ii) to a transload site from which customers can take possession or iii) to a third party for lease of rail cars which are then leased to other customers to transport the product to the customer’s location, and it is included in cost of goods sold. Less than 3% and 1% of our revenues for the three months ended March 31, 2013 and 2012, respectively, were derived from transportation charges.

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

Fair Value of Financial Instruments

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

The Predecessor financial instruments consist primarily of cash and cash equivalents, accounts receivable, accounts payable and debt instruments. The carrying amounts of financial instruments, other than the debt instruments, are representative of their fair values due to their short maturities. We determined the fair value of the Predecessor’s debt instruments using Level 2 inputs.

Concentration of Credit Risk

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

We provide credit, in the normal course of business, to customers located throughout the United States. We perform ongoing credit evaluations of our customers, generally do not require collateral and evaluate the potential credit losses regularly, which, when realized, have been within the range of management’s expectations.

8

Table of Contents

Our largest two customer balances represented 14% and 13% of the trade accounts receivable balance as of March 31, 2013 while the top two customer balances represented 15% and 14% as of December 31, 2012, respectively. No other customer balance exceeded 10% of the total trade accounts receivable balance as of March 31, 2013 and December 31, 2012.

No individual customer represented more than 10% of revenues for the three months ended March 31, 2013 and the three months ended March 31, 2012.

Accounts Receivable and Allowance for Doubtful Accounts

Trade accounts receivable are recognized at their invoiced amounts and do not bear interest.  We maintain an allowance for doubtful accounts for estimated losses resulting from the inability of its customers to make required payments.  We estimate our allowances based on specifically identified amounts that are believed to be uncollectible.  If the financial condition of our customers were to deteriorate, resulting in an impairment of their ability to make payments, additional allowances might be required.  After all attempts to collect a receivable have failed, the receivable is written off against the allowance. The allowance for doubtful accounts was $0.15 million at March 31, 2013, and $0.12 million at December 31, 2012.

Inventories

Finished goods inventories consist of dried sand and refined motor fuel products. All inventories are stated at the lower of cost or market using the average cost method. Raw materials inventories consist of wet-sand stockpiles and transmix feedstock. Raw materials inventories are stated at the lower of cost or market using the average cost method. Overhead in our Sand segment is capitalized at an average rate per unit based on actual costs incurred. Our Fuel segment does not capitalize overhead to its refined transmix inventory because turnover is high and the quantities are generally modest in comparison to our finished fuel inventories we purchase from third party refiners. We perform periodic physical inventory measurements to verify the quantity of our sand inventory and daily inventory measurements to verify fuel inventory quantities. We currently source the majority of our wet sand through suppliers where the resulting raw material cost is relatively fixed. In our Fuel segment, we do not have long-term contracts with any suppliers of petroleum products covering more than 10% of its motor fuel supply.

Motor Fuel Taxes

We report excise taxes on motor fuels on a gross basis. Excise taxes included in fuel revenues and cost of fuel amounted to approximately $10.8 million and $5.6 million for the three months ended March 31, 2013 and 2012, respectively.

Direct Financing Lease Receivable

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

9

Table of Contents

Property, Plant and Equipment, net

We recognize purchases of property, plant and equipment at cost, including capitalized interest, where necessary. Maintenance, repairs and renewals are expensed when incurred. Additions and significant improvements are capitalized. Disposals are removed at cost less accumulated depreciation and any gain or loss from dispositions is recognized in income.

Depreciation and amortization of other property, plant and equipment is provided for, commencing when such assets become operational, on the straight-line basis over the following estimated useful lives.

Mineral Resources, net

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

Deferred Public Offering Costs

Deferred financing and public offering costs include deferred public offering costs amounting to $3.9 million and $3.7 million as of March 31, 2013 and December 31, 2012, respectively, and consist of professional fees incurred related to the public offering. These costs were deferred and charged against the proceeds of the IPO subsequent to March 31, 2013.

Intangible Assets

Intangible assets consist of trade names and customer relationships. Trade names are amortized on a straight-line basis over 10 years, and customer relationships are amortized using the economic benefits method over 15 years.

Derivative Instruments and Hedging Activities

We account for derivatives and hedging activities in accordance with Financial Accounting Standards Board (the “FASB”) Accounting Standards Codification (“ASC”) 815-10-05, Accounting for Derivative Instruments and Certain Hedging Activities, which requires entities to recognize all derivative instruments as either assets or liabilities in the balance sheet at their respective fair values. For financial instruments that do not qualify as an accounting hedge, changes in fair value of the assets and liabilities are recognized in earnings. Our policy is to not hold or issue derivative instruments for trading or speculative purposes. Additional disclosures for derivative instruments are presented in Note 10.

Business Segments

We have two operating and reporting segments. The Sand segment consists of the production and sale of various grades of industrial sand primarily used in the extraction of oil and natural gas and the production of building products and foundry materials. The Fuel segment consists of purchasing, blending, distribution, and the transportation of light petroleum products used primarily as motor fuels. We operate a distillation tower that extracts gasoline and diesel fuel from commingled motor fuels and also operate a biodiesel refinery. Our chief operating decision maker is our chief executive officer. The chief operating decision maker allocates resources and assesses performance of the business and other activities at the reporting segment level.

10

Table of Contents

3.              INVENTORIES

Inventories consisted of the following:

4.              LONG-TERM DEBT

Senior Secured Credit Facilities

Prior to our IPO, we maintained several senior secured credit facilities. In our Sand Segment we maintained a $60 million credit facility that was comprised of a $30 million Term A note, a $20 million capital expenditure Term B line of credit and a $10 million operating revolving credit facility that had a borrowing base in excess of the $10.0 million maximum commitment as of March 31, 2013. All facilities accrued interest at LIBOR plus 425 basis points (4.45% as of March 31, 2013). The revolving credit facility was secured by substantially all of our Sand segment accounts receivable and inventory and the term loans had first lien positions on all the remaining assets in our Sand segment. The senior secured credit facilities required us to maintain certain debt covenants related to leverage and tangible net worth. We repaid all amounts outstanding under the revolving credit and senior term loan facilities in full at the closing of our IPO.

In our Fuel segment, we maintained a senior secured credit facility consisting of a revolving credit facility and a term loan, both collateralized by substantially all of our Fuel segment assets. The revolving credit facility had a maximum commitment of $15.0 million with $2.5 million and $2.0 million of availability as of March 31, 2013 and December 31, 2012, respectively. The term loan had outstanding borrowings of $18.2 million and $18.4 million as of March 31, 2013 and December 31, 2012, respectively. Due to a troubled debt restructuring on April 1, 2011, the carrying value of the loan, $20.4 million as of March 31, 2013, does not equal the total future principal cash payments of $18.2 million. The difference between carrying value and total future principal cash payments results from the application of accounting rules for a troubled debt restructuring. The difference between the carrying value of the term loan and the restructured liability is reduced interest costs over the term of the credit agreement governing the senior secured credit facility, and interest payments to the term loan reduce the carrying value of the term loan.

The following table reconciles lender records to the modified carrying value of our term loan at March 31, 2013:

The maturity date of the revolver and term loan was April 1, 2015. The revolver loan and term loan accrued interest monthly at a rate equal to either (a) the base commercial lending rate of the bank as publicly announced plus applicable margin or (b) a rate equal to London interbank offered rates (LIBOR) plus applicable margin which was tied to our financial performance. As of March 31, 2013 and December 31, 2012, we elected the LIBOR option for $5,000,000 of our revolver and $18,000,000 of the term loan. The LIBOR option for the revolver loan and term loan was from March 29, 2013 to April 29, 2013. We did not renew our LIBOR election after April 29, 2013. The remaining portions for both the revolver and term loan were included under the bank’s base commercial lending rate plus applicable margin. As of March 31, 2013, the LIBOR rate plus applicable margin was 4.2037% for the revolver and 4.7037% for the term loan. For the remaining principal portion priced under the bank’s base commercial lending rate plus applicable margin, the interest rate was 5.25% and 5.75% for the revolver and term loan, respectively. The credit agreement had a term loan prepayment arrangement whereby we were required to remit 50% of excess cash flow beginning thirty days after delivery of the 2012

11

Table of Contents

audited financial statements to the senior lenders and continuing annually thereafter until maturity. Based on 2012 financial results and the credit agreement terms controlling the prepayment, we did not owe the conditional prepayment. As a result, we classified the entire outstanding balance of the long-term debt in accordance with the fixed contractual repayment terms as of March 31, 2013. We repaid all amounts outstanding under the revolving credit and senior term loan facilities in full at the closing of our IPO.

Second Lien Credit Agreement

On September 7, 2012, we entered into a third amended and restated credit agreement with LBC Credit Partners, LP and other lenders named therein, which was scheduled to mature on March 7, 2017. As of March 31, 2013 and December 31, 2012, we had $43.5 million and $41.8 million, respectively, in outstanding borrowings bearing a cash interest rate of 12% per annum and an additional 6% per annum ‘‘in-kind’’ through an increase in the outstanding principal amount of the loan. We repaid the second lien term loan in full at the closing of our IPO.

Third Lien Credit Agreement

On September 7, 2012, we entered into a first amended and restated credit agreement with an affiliate of the owner of our general partner and other lenders named therein. At March 31, 2013, we owed $5.3 million under this arrangement. The credit agreement governed our third lien term loan, which was scheduled to mature on September 7, 2017 and bore interest at a rate of 0% per annum. We repaid the third lien term loan in full at the closing of our IPO.

Other Long-Term Debt

From time to time, we incur additional debt to finance annual insurance premiums or certain specific equipment purchases. Total principal amounts of such borrowings were $0.9 million and $1.2 million as of March 31, 2013 and December 31, 2012, respectively.

The following table represents the estimated maturities of the Predecessor’s long-term debt as of March 31, 2013:

5.              ADVANCES FROM CUSTOMERS

During 2011, we entered into agreements with three customers (the “Sand Supply Agreements”) that included customer prepayment provisions. We received advanced payments from three customers in the following amounts: customer 1 - $8,000,000; customer 2 - $5,000,000; customer 3 - $3,000,000 (customer 3 was paid in full in 2012). The repayment periods range from two to three years for each of the Sand Supply Agreements.

We have agreed to repay the advance payments, including interest, during the repayment period by applying against the full invoiced amount a credit ranging from $10.00 to $11.50 per ton depending on the grade of sand being purchased. The current and long-term portions of these obligations have been estimated based on future expected purchase quantities or the minimum required purchases, whichever is greater.

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

12

Table of Contents

6.              COMMITMENTS AND CONTINGENCIES

Litigation and Potentially Uninsured Liabilities

We maintain general liability insurance with limits and deductibles that management believes prudent in light of our exposure to loss and the cost of the insurance.  We are subject to various claims and litigation arising in the ordinary course of business.  As of March 31, 2013, there is no accrued loss for such claims and litigation based on management’s review of the existing facts and circumstances and based on the advice of counsel.  The legal expenses related to claims and litigations are expensed when incurred.  In addition, we had been involved in an arbitration case brought by a former supplier that was settled by an agreement in October 2010.  The supplier has raised issues regarding the settlement but management believes that the settlement will be enforced.  In the opinion of management, the outcome of the above arbitration will not have a material adverse effect on the liquidity, financial position or results of operations of the Company.

Internal Revenue Service Audit

The Sand segment underwent an audit by the Internal Revenue Service (“IRS”) for the year ended December 31, 2009.  The IRS accepted the 2009 return as originally filed with no proposed changes.

The Fuel segment was audited by the IRS for tax years 2008 and 2009.  The IRS field examination is complete and the IRS issued its findings.  Management protested the findings through IRS appeal channels.  The IRS appeal conference has not been scheduled. Management believes that the outcome will not have a material effect on the financial position, liquidity or results of operations of the Company.

Employment Agreement

Prior to our IPO, we had a long-term incentive compensation program (the “LTIC”) with our chief executive officer and a consultant under which additional compensation may be paid based on certain events, as defined in the agreement.  As of March 31, 2013, there were no amounts due under the LTIC. However, in connection with our IPO, we made payments to these individuals as consideration for terminating this particular LTIC plan.

Excise Tax Penalty

In 2012, we received an IRS penalty totaling $340,000 due to failure to file terminal operator reports in electronic format. We filed these returns in paper format.  Management protested the audit findings through IRS appeal channels.  Management placed the IRS on notice that it plans to claim exception from penalty due to reasonable cause.  The IRS appeal conference has not been scheduled.  In the opinion of management, the outcome of such matters will not have a material effect on our financial position, liquidity or results of operations.

Litigation Settlement Expense

In December 2012, we settled litigation that alleged environmental damage to property located contiguous to our bulk fuel terminal facility.  The settlement agreement extinguished all liabilities, if any, and it included mutual releases between the parties.  We paid $750,000 to settle this litigation, which cost has been allocated to our Fuel segment.

Other

We are subject to various claims and litigation arising in the ordinary course of business.  In the opinion of management, the outcome of such matters will not have a material effect on our financial position, liquidity or results of operations.

7.              RELATED PARTY TRANSACTIONS

We made aggregate principal and interest payments to related party lenders of $0.6 million and $0 for the three months ended March 31, 2013 and 2012.  During the three months ended March 31, 2012, we incurred an amendment fee of $334,500 related to its subordinated long-term debt that is held by a member of the Predecessor.

Other related party transactions include reimbursements of certain general and administrative expenses incurred by a member on our behalf of approximately $0.2 million and $0.2 million for the three months ended March 31, 2013 and 2012, respectively.  As of March 31, 2013 and December 31, 2012, amounts included in trade accounts payable and accrued expense due to a member were approximately $0.5 million and $0.2 million, respectively.

13

Table of Contents

8.              SEGMENT REPORTING

We group our activities into two business segments:  (i) the production and sale of various grades of sand primarily used in the extraction of oil and natural gas and the production of numerous building products and foundry materials, or the Sand segment; and, (ii) the refining of transmix, distribution of finished fuel products, terminal and reclamation activities, and refining biodiesel, or the Fuel segment. We allocate all administrative overhead to the Sand and Fuel segments.  The Predecessor conducts its business primarily in the United States and Canada with no other international operations.

The Sand and Fuel segments are separately managed under a structure that includes “Segment Managers” who report to our “Chief Operating Decision Maker” (CODM) (terms as defined in ASC 280).  The CODM is our chief executive officer, who reports to the board of directors.  Our Sand and Fuel operations represent components, as described in accounting standards for segment reporting (ASC 280), that engage in activities (a) from which revenues are earned and expenses incurred; (b) whose operating results are regularly reviewed by the CODM, which makes decisions about resources to be allocated to the business segments and assess their financial performance; and (c) for which discrete financial information is available.

Segment managers for the Sand and Fuel segments are directly accountable to and maintain regular contact with our CODM to discuss segment operating activities and financial performance.  With concurrence and approval of the board of directors, the CODM approves annual capital budgets for major projects.  However, business unit managers within the operating segments are responsible for decisions relating to project implementation and matters connected with daily operations.

We evaluate the performance of operating segments using the non-GAAP performance metric of earnings before interest, income tax expense, depreciation, depletion, and amortization (“EBITDA”).  We further adjust EBITDA to exclude the effects, if any, of non-cash charges and unusual or non-recurring charges less interest income, tax benefits and selected gains that are unusual or non-recurring.  The result of this computation yields the performance metric of Adjusted EBITDA.  We compute Adjusted EBITDA generally as: net income plus interest expense, income tax expense, depreciation, depletion and amortization expense, non-cash charges and unusual or non-recurring charges less interest income, tax benefits and selected gains and losses from disposal of assets.  Management does not consider these items as part of its routine evaluation of segment performance.

The following tables illustrate operating segment revenues and earnings together with reconciliation to consolidated results.  Asset information, including capital expenditures, by segment is not used by management in its monitoring of performance and, therefore, is not reported by segment.

14

Table of Contents

(a)  For segment reporting purposes, operating expenses exclude depreciation and amortization.

(b)  For segment reporting purposes, operating income excludes gain (loss) on disposal of equipment.  Management does not consider asset transactions in its approach to segment performance evaluation.

9.              EMPLOYEE BENEFITS

401(K) Retirement Plan

We sponsor two retirement plans that are available to all employees who have met certain continuous service requirements and cover substantially all employees of SSH and AEC Holdings.  The plans are subject to the provisions of the Employee Retirement Income Security Act of 1974 (ERISA) and are qualified under Section 401(k) of the Internal Revenue Code. In our Sand segment, we match 100% of employee contributions up to the first 4% of each employee’s pay.  Additionally, we may make a discretionary contribution as deemed appropriate.  Although discretionary by management, in our Fuel segment we traditionally match 100% of employee contributions up to the first 5% of the participant’s pay but may not exceed the maximum amount deductible under the applicable provisions of the Internal Revenue Code.  Contributions to the retirement plans were $73,000 and $41,000 for the three months ended March 31, 2013 and 2012, respectively.

10.       FAIR VALUE MEASUREMENTS

Our financial instruments consist primarily of cash and cash equivalents, accounts receivable, accounts payable, and debt instruments.  The carrying amounts of financial instruments, other than the debt instruments, are representative of their fair values due to their short maturities.  Our long-term debt instruments bear interest at market rates, and thus management believes their carrying amounts approximate fair value. We determined the fair value of our debt instruments using Hierarchy Level 2 inputs.

We periodically entered into interest rate swaps and futures contracts in accordance with its risk management strategy to manage the risk associated with changing interest rates and fuel prices. We do not use derivative financial instruments for trading or speculative purposes. As of March 31, 2013 and December 31, 2012, we did not have any outstanding interest rate swaps.  As of March 31, 2013 and December 31, 2012, we had 119 and 188 open contracts, respectively, to manage fuel price risk.  For the three months ended March 31, 2013, the realized gains from fuel-related futures amounted to $0.1 million and unrealized losses amounted to $0.2 million. For the three months ended March 31, 2012, the realized losses from fuel-related futures amounted to $0.8 million and unrealized gains amounted to $0.1 million.  These amounts are reported in cost of fuel in the unaudited condensed combined statements of operations.

We adopted FASB ASC 820, which defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. FASB ASC 820 applies to other accounting pronouncements that require or permit fair value measurements; however, it does not require any new fair value measurements.

15

Table of Contents

FASB ASC 820 establishes a valuation hierarchy for disclosure of the inputs to valuation used to measure fair value. This hierarchy prioritizes the inputs into three broad levels as follows.

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

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

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

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

A financial asset or liability’s classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement.  The following table provides the assets and liabilities carried at fair value measured on a recurring basis:

11.       SUBSEQUENT EVENTS

We evaluated subsequent events through the date the financial statements were issued.  Certain significant events have occurred requiring disclosure:

Initial Public Offering of Emerge Energy Services LP

On May 8, 2013, the Partnership priced an initial public offering of 7,500,000 common units at a price to the public of $17.00 per unit ($15.98 per common unit, net of underwriting discounts). The IPO was made pursuant to a registration statement on Form S-1 originally filed on March 22, 2013, as amended (Registration No. 333-187487) that was declared effective by the SEC on May 8, 2013. On May 20, 2013, the underwriters exercised their option to purchase an additional 209,906 common units. The net proceeds from the IPO of approximately $122.2 million (including over commitment allocation of $3.3 million), after deducting the underwriting discount and the structuring fee, were used to: (i) repay existing subsidiary debt, in the amount of approximately $87.6 million, (ii) pay offering expenses of approximately $10.6 million, (iii) pay cash-based compensation awards to senior management of approximately $8.9 million, (iv) provide the Partnership with working capital of approximately $11.5 million and (v) provide a distribution to equity holders of $3.6 million.

In connection with the closing of the IPO, SSH and its affiliates contributed their interests in Superior Silica Sands LLC (“SSS”), AEC Holdings contributed its interest in Allied Energy Company LLC (“AEC”) and Direct Fuels Partners, L.P. (“DF Parent”) contributed its interest in Direct Fuels LLC (“DF”) to the Partnership, and the Partnership issued an aggregate of 23,219,680 common units.

Upon the closing of the IPO, the consolidated historical financial statements of SSH, AEC Holdings, and the Partnership became the historical financial statements of the Partnership.

Agreements with Affiliates

Services Agreement.  On May 14, 2013, in connection with the closing of the IPO, the Partnership entered into an administrative services agreement with Insight Equity Management Company, LLC (“Insight Management”), pursuant to which Insight Management provides specific general and administrative services to us and our subsidiaries from time to time.  Under the terms of the agreement, we reimburse Insight Management based on agreed upon formulas on a monthly basis for actual travel and other expenses incurred by Insight Management and for legal work provided by the general counsel of Insight Management on our behalf. In addition, an executive employee of Insight Management is the head of the Fuel segment. The Partnership will reimburse Insight Management for the allocation of the Insight Management executive’s time incurred in providing services to the Partnership.  The administrative services agreement will remain in force until (i) the date the Partnership and Insight Management mutually agree to terminate it; (ii)

16

Table of Contents

the final distribution in liquidation of the Partnership or the Partnership’s subsidiaries; or (iii) the date on which neither Insight Management nor its affiliates collectively control less than 51% of the Partnership.

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

New Credit Facility

On May 14, 2013, the Partnership entered into a new $150 million senior secured revolving credit facility and initially borrowed approximately $112.7 million under that revolving credit facility.  The Partnership used the proceeds from these borrowings to (i) make distributions of $17.0 million and $22.2 million to SSH and DF Parent, respectively, and (ii) repay $73.5 million of existing subsidiary debt. The Partnership’s borrowings under the new revolving credit facility initially bear interest at approximately 3.78%.  The new credit facility will be available to repay existing indebtedness of the Partnership on the closing date of the IPO, to fund fees and expenses incurred in connection with the IPO and the credit facility, and for general business purposes, including working capital requirements, capital expenditures, permitted acquisitions, making debt payments (but not prepayments) when due, and making distributions and dividends. In addition, the Credit Agreement includes a sublimit of up to $15 million for the issuance of letters of credit. Substantially all of the assets of the Partnership and the Borrowers under the Credit Agreement are pledged as collateral under the Credit Agreement.

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

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

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

Loans under the credit facility will bear interest at the Partnership’s option at either:

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

·                  LIBOR plus an applicable margin ranging from 2.75% to 3.50% based on the Partnership’s total leverage ratio.

The new revolving credit facility will mature on May 14, 2018.

Acquisition of Direct Fuels

In connection with the IPO, the Partnership acquired DF from DF Parent for $76.6 million on May 14, 2013.  DF operates a motor fuel terminal and transmix processing facility in Texas.  The Partnership acquired DF to expand its operations to gain new customers, improve margins, and increase its markets through a larger geographical presence.  After completing the acquisition on May 14, 2013, the Partnership owned 100% of DF.  The Partnership funded the acquisition with a combination of cash and restricted common units.

17

Table of Contents

Long-Term Incentive Compensation Plan

Effective May 14, 2013, the Partnership adopted the Emerge Energy Services LP 2013 Long-Term Incentive Plan (the “LTIP”) for providing long-term incentives to certain employees of the Partnership.  The plan provides for the following compensation:

i)               Incentive compensation based on growth of the Partnership’s distributions to shareholders.

ii)              Incentive compensation based on the appreciation in value of the Partnership’s shares.

iii)           Incentive phantom shares that vest over a defined or undefined period.

Certain components of the LTIP are consistent with ASC 718, Compensation – Stock Compensation, while other components are consistent with ASC 710, Compensation – General.  Management intends on recognizing compensation expense in a manner consistent with the appropriate guidance.

Emerge Energy Services LP Director Compensation Program

On May 14, 2013, the Board adopted the Emerge Energy Services LP Director Compensation Program (the “Director Plan”). Any non-employee director not affiliated with the partnership, our general partner, or certain Insight Management affiliates is eligible to receive awards under the Director Plan. Under the Director Plan, each eligible director will be entitled to receive an annual cash retainer of $50,000. In addition, each committee chairperson will receive a $10,000 annual cash retainer and each non-chair committee member will receive a $2,500 annual cash retainer. Annual retainers will be paid in cash quarterly in arrears and will be paid effective as of the first day of the calendar quarter in which the IPO occurred. Other than with respect to the calendar quarter in which the IPO occurred, annual retainers will be pro-rated to reflect any partial year of service.  Under the Director Plan, each eligible director serving on the Board at the closing of the IPO was granted 3,529 restricted units on the date of the closing of the IPO. These awards will vest in full on the first anniversary of the grant date, subject to continued service.

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

18

Table of Contents

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

You should read the following discussion of our historical performance, financial condition and future prospects in conjunction with our unaudited condensed financial statements and accompanying notes in “Item 1. Financial Statements” contained herein and our Predecessor’s audited consolidated financial statements as of December 31, 2010, 2011 and 2012, included in our prospectus relating to our initial public offering, as filed with the Securities and Exchange Commission on May 10, 2013. The information provided below supplements, but does not form part of, our unaudited condensed financial statements or our predecessor’s financial statements. This discussion contains forward-looking statements that are based on the views and beliefs of our management, as well as assumptions and estimates made by our management. Actual results could differ materially from such forward-looking statements because of various risk factors, including those that may not be in the control of management. See “Forward-Looking Statements” on page 30.

General

Emerge Energy Services LP, or the Partnership and its subsidiaries (collectively with the Partnership, “we,” “us” or “our”) is a growth-oriented limited partnership formed by management and affiliates of Insight Equity Management Company LLC to own, operate, acquire and develop a diversified portfolio of energy service assets. Upon the closing of the IPO on May 14, 2013, 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, or Fuel, 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 currently consists of advanced facilities in New Auburn, Wisconsin, Barron County, Wisconsin, and Kosse, Texas that are optimized to exploit the reserve profile in place at each location and produce high quality frac sand. Frac sand is a critical component sold to and used by oilfield service companies to stimulate and maintain the flow of hydrocarbons in oil and natural gas wells that utilize hydraulic fracturing techniques. Our Wisconsin sand reserves provide us access to a wide range of high-quality sand that meets or exceeds all API specifications and includes coarse sands such as 16/30, 20/40 and 30/50 mesh sands, which have become the preferred sand for oil and liquids-rich gas drilling applications due to their coarseness, conductivity, high crush strength and comparative cost advantages over resin-coated sand or ceramic alternatives. Through our Wisconsin sand facilities and their interconnectivity to rail and other logistics infrastructure, we believe we are one of only a select group of sand producers capable of efficiently delivering the most highly sought after types of frac sands to all major unconventional resource basins currently producing in the United States and Canada. Our locations in Wisconsin also provide our customers with economical access to barging terminals on the Mississippi River as well as access to Duluth, Minnesota, for loading onto ocean going vessels for international delivery. We also mine frac sand at our facility in Kosse, Texas that is processed into a high quality, 100-mesh frac sand, generally used in dry gas drilling applications. Because of the quality and diversity of our sand reserves, we have the operational flexibility to alter a portion of our produced sand mix to meet customer needs across different price environments.

Our Fuel segment consists of facilities located in Birmingham, Alabama. Through this segment, we acquire refined petroleum products and transmix. Transmix is a blend of different refined petroleum products that have become co-mingled in the pipeline transportation process, and process it into refined products such as conventional gasoline and low sulfur diesel. We design our pricing structure to capture a stable margin, as the price differential between the indices at which we purchase transmix and wholesale supply and the sales price. In addition to processing transmix and selling refined products, we provide a suite of complementary fuel products and services, including third-party terminalling services, sale and distribution of wholesale motor fuel petroleum products, certain reclamation services (which consist primarily of tank cleaning services), blending of renewable fuels, and refining biodiesel.

How We Generate Our Revenues

Sand Segment

We derive our sales by mining, processing and distributing frac sand that our customers purchase in connection with the application of hydraulic fracturing techniques to oil and natural gas wells. As the majority of our sales volume is contracted for delivery at the mining facility such that the customer bears the shipping expense, our sales are primarily a function of the price per ton realized at the point of sale and the volumes sold. Sand sold from our New Auburn facility is largely picked up by our customers at that facility. In connection with the commencement of operations at the Barron facility, we are now increasingly managing the logistics of shipping frac sand directly from that facility to the major oil producing basins. This provides our customers, for a fee, with readily available

19

Table of Contents

frac sand that can be picked up by truck from a site close to the wellhead. Our transportation revenues fluctuate based on a number of factors, including the volume of product we transport, service agreements with our customers, the mode of transportation utilized, the distance between our plants and customers, and the mode of transloading and storage utilized at the destination.

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

For one of the two customers mentioned above, we anticipate extending the contract term, which expires in 2014 or, alternatively, replacing those sales volumes by entering into agreements with new customers. However, we may not be able to enter into new long-term contracts that contain take-or-pay provisions or on terms that are as favorable to us as our current take-or-pay contracts. Our current take-or-pay agreements define, among other commitments, the volume of product that our customers must purchase, the volume of product that we must provide, and the price that we will charge and that our customers will pay for each product. Prices under these agreements are generally fixed and subject to adjustment, upward or downward, only for certain changes in published producer cost indices or market prices. As a result, our realized prices may not grow or decline at rates consistent with broader industry pricing. For example, during periods of rapid price growth, our realized prices may grow more slowly than those of competitors, and during periods of price decline, our realized prices may decline from their current level but could outperform industry averages.

At the time our two primary customers entered into take-or-pay supply agreements with us, these customers provided advance payments for future shipments aggregating $13.0 million ($1.5 million of these payments was recorded on the balance sheet as customer advances as of March 31, 2013) in exchange for cash discounts on the price charged per ton of sand. As a result, the cash we receive from these customers is less than the revenue we record for such sales. We anticipate the advances will be fully retired in the first half of 2013, thus eliminating the cash discount on purchased sand.

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

In a third type of contract, which we refer to as an efforts-based contract, our customer is required to use commercially reasonable efforts to purchase the quantities of sand set forth in the agreement. These long-term efforts-based agreements contain pricing terms similar to those of our fixed-volume agreements and do not include pre-determined liquidated damage provisions in the event the customer fails to purchase the quantity specified in the agreement. The customer’s failure to purchase the quantity specified in an efforts-based agreement in a given year does not reduce the amount that the customer must use commercially reasonable efforts to purchase under that agreement in the following year.

We also entered into a tolling agreement whereby we will provide dry sand conversion services at a fixed price per ton. The tolling agreement does not obligate the counterparty to use our dry sand conversion services.  However, if they fail to supply a minimum quantity of wet sand under the agreement, our purchase price per ton of wet sand will be reduced, retroactively.

Collectively, sales to customers with long-term take-or-pay sales agreements in the first quarter of 2013 accounted for approximately 82% of our total Sand segment sales volumes. Sales to fixed-volume customers comprised another 6% of our total Sand segment sales volumes.  The remaining 12% of sales were to spot-market customers, most of whom we are actively working to convert into contract customers.  As of March 31, 2013, our long-term take-or-pay agreements tied to New Auburn plant customers covered approximately 58% of our 1.3 million tons of the plant’s annual production capacity, while 410,000 tons of the Barron dry plant’s 2.4 million tons of capacity is committed to other contract customers under a combination of take-or-pay, fixed-volume, and long-term efforts-based contracts. Additionally, we believe that a combination of high quality sand reserves, a highly customizable production mix, efficient production operations and our broad portfolio of flexible supply chain solutions, including unit train delivery, provide us a competitive advantage when competing for sales volume in the spot market.

We invoice the majority of our clients on a per shipment basis, although for some larger customers, we consolidate invoices weekly or monthly. Our standard terms require customer payments within 30 to 35 days of invoice date. The amounts invoiced include the

20

Table of Contents

amount charged for the product, the transportation costs (if any) and, as applicable, costs for additional services, such as costs related to product transloading, storage and rail car maintenance, cleaning or storage.

Fuel Segment

We derive substantially all of our Fuel segment revenues by selling motor fuel petroleum products to wholesalers, retailers, and end users in the greater Birmingham, Alabama market.  In addition, we provide terminal bulk fuel storage (“terminalling”), reclamation, and certain freight services to our customers, which collectively constituted approximately 2% of our Fuel segment sales in the first quarter of 2013.

We sell our fuel to a broad customer base using a mix of contract and spot sales. Our sales contracts define the price formula at which we sell to contract customers. While prices for contract customers tend to be slightly below prices for spot customers, our contract customers provide a consistent and reliable base of revenue. Prices for contract customers are tied directly to daily fuel price indices and for other customers are based on market rates that approximate what other sellers of unbranded fuel are charging in the Birmingham market on any given day.

Our terminalling customers pay us a fee for every gallon of fuel that they sell across our truck rack. In addition, other fees may be charged for certain additives and injection services. We provide customers with reclamation services, primarily tank cleaning, on a fee-for-service basis. We also have a truck fleet for hauling petroleum products that supports our reclamation and transmix business. We use these vehicles primarily for in-house activities but we also provide transportation services for outside customers on a limited basis.

Our Fuel segment invoices its customers daily. Generally, our customers remit payment through a draw on their bank accounts 10 days after the invoice date.  Amounts due for terminalling and reclamation services generally reflect 30 day payment terms.

The Costs of Conducting Business

Sand Segment

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

We incur costs related to direct labor at our facilities; we do not employ any union labor.  Additionally, we incur expenses related to our corporate operations, including costs for selling and marketing; research and development; finance; legal; and environmental, health and safety functions of our Sand operations. These costs are principally driven by personnel expenses.

We capitalize the costs of our mining equipment and generally depreciate it over its expected useful life. Preventive and remedial repair and maintenance costs that do not involve the replacement of major components of our equipment and facilities are expensed as incurred. These repair and maintenance costs can be significant due to the abrasive nature of our products. We incur significant costs for electricity and drying fuel (principally natural gas) in connection with the operation of our processing facilities. All of our plants are serviced by three-phase power and natural gas lines.

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

21

Table of Contents

We engaged a specialized third party contractor to perform the mining operations at our New Auburn location and to satisfy a portion of our wet processing needs at that facility. Under our agreement with this mining contractor, we agreed to purchase a minimum number of tons of washed sand under take-or-pay conditions each year until the contract expires in September 2016. A portion of the cash payment we make to our mining contractor under the agreement is treated as a capital lease payment, given that we will own the plant at the end of the capital lease period. The cost of goods sold reflected in our financial statements includes only the portion of the payment that is not attributable to the capital lease payment. Recognized contract mining and wet processing fees due to the mining contractor represented our largest operating expenditure in the three months ended March 31, 2013, accounting for approximately 13% of our revenues in that period. We anticipate this mining contractor will continue to represent a material portion of our cost structure for the next several years and have negotiated fixed rates, which adjust based on actual volume purchased, for the services provided during that time.

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

Fuel Segment

The cost of goods, which includes cost of fuel and labor, is the most significant expense that we incur: accounting for approximately 97% of operating costs for the three months ended March 31, 2013. We purchase our transmix, wholesale fuel and other feedstocks based on several different regional price indices, the most important of which are Platt’s Gulf Coast gasoline and diesel price postings. The price of our purchases is set generally on the day we purchase the product. We typically sell our fuel within 7 to 10 days of our purchase. When there are large surges in our supply of transmix, our holding period for inventory can increase but it tends to normalize within a short period. We use hedging products for our Fuel Processing and Distribution operations in order to stabilize our margins with respect to diesel and gasoline.

Sale of products from our transmix operations represented approximately 16% of our fuel revenues for the three months ended March 31, 2013. Wholesale fuel represents the remainder of our fuel purchases. Our reported fuel revenues and cost of fuel both include state and federal excise taxes that we collect on behalf of governmental bodies and then remit to them on a periodic basis. These taxes have no impact on our profitability.  Other costs relating to selling, administrative, depreciation and amortization expenses collectively represent our remaining operating costs.

How We Evaluate Our Operations

Our management uses a variety of financial and operational metrics to analyze our performance. Our business is organized into our Sand segment and our Fuel segment. We evaluate the performance of these segments based on their volumes sold, gross profit per unit, segment gross profit, selling, general and administrative expenses and Adjusted EBITDA. We view these metrics as important factors in evaluating our profitability and review these measurements frequently to analyze trends and make decisions.

Sales Volumes

We view the total volume of refined fuel products and frac sand that we sell as an important measure of our ability to effectively utilize our assets. Higher volumes improve profitability through the spreading of fixed costs over greater volumes. For our Sand segment, the ratio of sand sold that is tailored to dry gas applications versus oil and liquids-rich gas applications is important because changing commodity prices can influence spot market margins for each product set. Although winter weather impacts the months during which we can wash frac sand in Wisconsin, seasonality is not a significant factor in determining our ability to supply sand to our customers because we are able to sell frac sand year-round by accumulating a stockpile of wet sand during non-winter months and then dry-process and sell that sand during winter months. However, we may also be selling frac sand for use in oil- and gas-producing basins where severe weather conditions may curtail drilling activities and, as a result, our sales volumes to those areas may be adversely affected. For example, we could experience a decline in volumes sold and Adjusted EBITDA for the second quarter relative to the first quarter each year due to seasonality of frac sand sales to customers in western Canada as sales volumes are generally lower during the months of April and May due to limited drilling activity as a result of that region’s annual thaw. Generally, our Fuel segment does not experience dramatic seasonal shifts in quantities delivered to its customers.

Gross Profit per Unit

The product margin per gallon that we realize for selling gasoline or diesel is the difference between the price that we pay to buy the product, including the cost of inbound transportation, the cost of any additives that may be blended with the product, certain direct operating and maintenance expenses, and the price at which we sell that product to our customers. We believe this is the best measure

22

Table of Contents

of the profitability of each gallon of our refined product. The product margin for frac sand is the difference between the cost to mine each ton of sand considering both the wet and dry operations and the price at which we sell each ton as determined by our sales contracts or by the then prevailing market price if it is a spot sale. When we sell product to the customer at a location near the drill site, our margin is incrementally impacted by the price we receive for the supply chain services rendered, net of our transportation, transload, and storage costs.

Segment Gross Profit

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

Selling, General and Administrative Expenses

In addition to the foregoing measures, we also monitor our selling, general and administrative expenses. These costs represent a small portion of our total costs; however, it is still very important to us that we control them. Our selling, general and administrative expenses include costs necessary to provide administrative support necessary to run our business. As a result of our initial public offering, we estimate that we will incur incremental general and administrative expenses of approximately $3.5 million per year as a result of being a publicly traded limited partnership. These costs include those associated with annual and quarterly SEC reporting; tax return and Schedule K-1 preparation and distribution expenses; Sarbanes-Oxley compliance expenses; expenses associated with listing on the NYSE; independent auditor fees; legal fees; investor relations expenses; registrar and transfer agent fees; director and officer liability insurance costs; and outside director compensation.

Adjusted EBITDA and Distributable Cash Flow

Our management and others use Adjusted EBITDA and distributable cash flow as supplemental measures of our financial statements 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 define Adjusted EBITDA generally as: net income plus interest expense, tax expense, depreciation, depletion and amortization expense, non-cash charges and unusual or non-recurring charges less interest income, tax benefits and selected gains that are unusual or non-recurring. We report Adjusted EBITDA (which as defined includes certain other adjustments, none of which impacted the calculation of Adjusted EBITDA herein) to our lenders under our new revolving credit facility in determining our compliance with the interest coverage ratio test and certain senior consolidated indebtedness to Adjusted EBITDA tests thereunder.  Adjusted EBITDA should not be considered as an alternative to net income, operating income, cash flow from operating activities or any other measure of financial performance presented in accordance with GAAP.

We define distributable cash flow as Adjusted EBITDA plus borrowings to fund growth capital expenditures, less cash paid for incremental annual general and administrative expenses of being a publicly traded partnership, cash paid for interest expense, and maintenance capital expenditures.  Distributable cash flow does not reflect changes in working capital balances.

23

Table of Contents

Results of Operations

The following table summarizes our Predecessor results of operations for the periods presented (in thousands).

24

Table of Contents

Three Months Ended March 31, 2013 Compared to Three Months Ended March 31, 2012

Interest expense was $4.2 million for the three months ended March 31, 2013 compared to $2.8 million for the three months ended March 31, 2012, an increase of $1.4 million, or 50%.  This increase was because of new debt to finance the construction of the Barron facility, offset by a reduction in total outstanding borrowings at our Fuel segment.

Net income was $9.9 million for the three months ended March 31, 2013 compared to $4.5 million for the three months ended March 31, 2012, an increase of $5.4 million, or 120%.  The primary drivers of this increase were the full operation of the Barron plant, additional sales at the New Auburn plant, and an increase in gross margin in our Fuel segment.

Sand Segment

Revenues

Revenues for our Sand segment were $32.1 million for the three months ended March 31, 2013, compared to $14.4 million for the three months ended March 31, 2012, an increase of $17.7 million, or 123%.  Sand sales volumes from our Barron County facility, which commenced operations in late 2012, accounted for $11.0 million of the increase, or 76%.  Revenues from our New Auburn facility increased $2.7 million, of which $4.2 million was from an increase in volumes shipped, which was offset $1.6 million by a decrease in average realized price per ton.  We also increased revenues from our Kosse facility by $0.3 million.  Other revenue increased by $3.7 million primarily because of higher transportation and logistics revenue.

Operating Expenses

Cost of goods sold for our Sand segment was $17.2 million for the three months ended March 31, 2013, compared to $5.7 million for the three months ended March 31, 2012, an increase of $11.5 million, or 202%.  This was primarily because of cost associated with production of sand from our Barron facility, offset by lower average cost of sales at our New Auburn facility, which had started up in late 2011.

Operations and maintenance expenses were $6.4 million for the three months ended March 31, 2013, compared to $1.8 million for the three months ended March 31, 2012, an increase of $4.6 million or 260%, primarily due to freight costs resulting from our decision to sell sand at a delivered price and increases in labor and utility costs associated with production of sand from our recently commissioned Barron facility.

General and administrative expenses were $2.2 million for the three months ended March 31, 2013 compared to $1.3 million for the three months ended March 31, 2012, an increase of $0.9 million, or 69%, primarily due to the increased hiring of individuals to manage the growth of the New Auburn and Barron operations.

Depreciation, depletion and amortization expenses were $2.4 million for the three months ended March 31, 2013 compared to $1.5 million for the three months ended March 31, 2012, an increase of $0.9 million, or 60%, primarily due to capital spending outlays related to the operation of the New Auburn facility and the construction of the Barron facility.

Operating Income

Operating income was $10.2 million for the three months ended March 31, 2013 compared to $6.0 million for the three months ended March 31, 2012, an increase of $4.2 million, or 70%, primarily because of increased sales volumes and a full three months of production from our Barron facility, which commenced operations in late 2012.

Fuel Segment

Revenues

Revenues for our Fuel segment were $109.9 million for the three months ended March 31, 2013, compared to $104.0 million for the three months ended March 31, 2012, an increase of $5.9 million, or 6%.  Revenues for sales of gasoline, blended gasoline and ethanol were $57.1 million for the three months ended March 31, 2013, compared to $54.7 million for the three months ended March 31, 2012, an increase of $2.4 million or 4%.  This increase was driven by an increase in the number of gasoline and blended gasoline gallons sold, as well as an increase in the average net realized price per gallon of ethanol, offset by a decrease in the number of gallons of ethanol sold as well as a slight decrease in the average net realized price per gallon of gasoline and blended gasoline sold.  Revenues for sales of diesel were $50.8 million for the three months ended March 31, 2013, compared to $47.8 million for the three

25

Table of Contents

months ended March 31, 2012, an increase of $3.0 million or 6%.  This increase was driven by an increase in the number of diesel gallons sold, offset by a slight decrease in the average net realized price per gallon of diesel sold.  Overall, the increase in gallons sold was driven by the addition of new wholesale customers.

Excise taxes on fuel sales were $10.8 million for the three months ended March 31, 2013, compared to $5.6 million for the three months ended March 31, 2012, an increase of $5.2 million or 93%.  This increase was driven by a new tax implemented by the State of Alabama (Alabama Terminal Excise Tax Act 2011-565) that requires invoicing customers for excise taxes at the rack, thereby shifting the burden of collecting and remitting these taxes to the terminal operator in lieu of the customer.  Revenues for our services segment were $1.9 million for the three months ended March 31, 2013, compared to $1.5 million for the three months ended March 31, 2012, an increase of $0.4 million, or 27%.  This increase was driven primarily by a $0.6 million increase in the sale of renewable fuel identifications numbers used to track compliance with U.S. Government renewable fuel standards and offset by a modest decrease in service fees.

Operating Expenses

Cost of fuel was $101.7 million for the three months ended March 31, 2013, compared to $98.6 million for the three months ended March 31, 2012, an increase of $3.1 million, or 3%, which was primarily due to the overall increase in volume and offset slightly by lower average fuel prices. Excise taxes on fuel purchases were $10.8 million and $5.6 million for the three months ended March 31, 2013 and 2012, respectively.  AEC offsets excise tax revenues against excise tax costs on a one-for-one basis. Operations and maintenance expenses were $2.6 million for the three months ended March 31, 2013, compared to $2.2 million for the three months ended March 31, 2012, an increase of $0.4 million or 18%, primarily because of the commencement of operations at our biodiesel plant in late 2012.

Operations and maintenance expenses were $2.6 million for the three months ended March 31, 2013, compared to $2.2 million for the three months ended March 31, 2012, an increase of $.4 million or 18%.  Operating supplies associated with the startup of our biodiesel refinery was the prime driver for the increase.

General and administrative expenses decreased by $0.1 million, or 6%, to $1.1 million for the three months ended March 31, 2013.  Depreciation, depletion and amortization expense was relatively unchanged at $0.7 million for the three months ended March 31, 2013.

Operating Income