EMES Emerge Energy Services LP Common Units Representing Limited Partner Interests

EMERGE ENERGY SERVICES LP

(Exact name of registrant as specified in its charter)

 

Delaware		90-0832937
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
5600 Clearfork Main Street, Suite 400, Fort Worth, Texas 76109		(817) 618-4020
(Address of principal executive offices)		(Registrant’s telephone number, including area code)

Large-Accelerated Filer   o		Accelerated Filer   x
Non-Accelerated Filer   o		Smaller Reporting Company   o
		Emerging growth company o

 

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•	failure to secure or maintain contracts with our largest customers, or non-performance of any of those customers under the applicable contract;

•	competitive conditions in our industry;

•	the amount of frac sand we are able to excavate and process, which could be adversely affected by, among other things, operating difficulties and unusual or unfavorable geologic conditions;

•	the volume of frac sand we are able to sell;

•	the price at which we are able to sell frac sand;

•	changes in the long-term supply of and demand for oil and natural gas;

•	volatility of fuel prices;

•	unanticipated ground, grade or water conditions at our sand mines;

•	actions taken by our customers, competitors and third-party operators;

•	our ability to complete growth projects on time and on budget;

•	our ability to realize the expected benefits from recent acquisitions;

•	increasing costs and minimum contractual obligations relating to our transportation services and infrastructure;

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

•	environmental hazards;

•	industrial accidents;

•	changes in laws and regulations (or the interpretation thereof) related to the mining and hydraulic fracturing industries, silica dust exposure or the environment;

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

•	facility shutdowns in response to environmental regulatory actions;

•	inability to obtain necessary production equipment or replacement parts;

•	reduction in the amount of water available for processing;

•	technical difficulties or failures;

•	labor disputes and disputes with our excavation contractor;

•	late delivery of supplies;

•	difficulty collecting receivables;

•	inability of our customers to take delivery of our products;

•	changes in the price and availability of transportation;

•	fires, explosions or other accidents;

•	pit wall failures or rock falls;

•	the effects of future litigation; and

•	other factors discussed in this Quarterly Report on Form 10-Q and the detailed factors discussed under the heading “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2017 .

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PART I                                            FINANCIAL INFORMATION

ITEM 1.                                       FINANCIAL STATEMENTS

 

EMERGE ENERGY SERVICES LP

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

($ in thousands, except unit data)

 

	September 30, 2018				December 31, 2017
ASSETS
Current assets:
Cash and cash equivalents	$	2,825			$	5,729
Trade and other receivables, net	30,068				56,951
Inventories	32,554				27,825
Prepaid expenses and other current assets	12,899				6,331
Total current assets	78,346				96,836
Property, plant and equipment, net	229,873				185,970
Intangible assets, net	58				1,664
Other assets, net	21,108				24,422
Total assets	$	329,385			$	308,892
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable	$	30,074			$	18,819
Accrued liabilities	16,478				29,718
Current portion of long-term debt	13,438				—
Total current liabilities	59,990				48,537
Long-term debt, net of current portion	182,866				176,351
Obligation for business acquisition, net of current portion	4,242				5,013
Other long-term liabilities	18,979				29,882
Total liabilities	266,077				259,783
Commitments and contingencies
Partners’ equity:
General partner	—				—
Limited partner common units - 31,034,338 units and 30,174,940 units issued and outstanding as of September 30, 2018 and December 31, 2017, respectively	63,308				49,109
Total partners’ equity	63,308				49,109
Total liabilities and partners’ equity	$	329,385			$	308,892

 

See accompanying notes to unaudited condensed consolidated financial statements.

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EMERGE ENERGY SERVICES LP

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

($ in thousands, except unit and per unit data)

 

	Three Months Ended September 30,								Nine Months Ended September 30,
	2018				2017				2018				2017
Revenues	$	62,961			$	103,215			$	271,553			$	261,161
Operating expenses:
Cost of goods sold (excluding depreciation, depletion and amortization)	52,337				80,239				205,229				223,978
Depreciation, depletion and amortization	5,316				6,078				15,532				16,409
Selling, general and administrative expenses	3,693				7,302				19,654				20,030
Contract and project terminations	—				—				1,689				—
Total operating expenses	61,346				93,619				242,104				260,417
Operating income (loss)	1,615				9,596				29,449				744
Other expense (income):
Interest expense, net	6,907				5,073				24,135				13,353
Other	(1,472		)		(901		)		(1,930		)		(3,218		)
Total other expense	5,435				4,172				22,205				10,135
Income (loss) from continuing operations before provision for income taxes	(3,820		)		5,424				7,244				(9,391		)
Provision (benefit) for income taxes	33				(58		)		183				(58		)
Net income (loss) from continuing operations	(3,853		)		5,482				7,061				(9,333		)
Income (loss) from discontinued operations, net of taxes	—				(468		)		—				(3,125		)
Net income (loss)	$	(3,853	)		$	5,014			$	7,061			$	(12,458	)
Earnings (loss) per common unit (1)
Basic:
Earnings (loss) per common unit from continuing operations	$	(0.12	)		$	0.19			$	0.23			$	(0.31	)
Earnings (loss) per common unit from discontinued operations	—				(0.02		)		—				(0.10		)
Basic earnings (loss) per common unit	$	(0.12	)		$	0.17			$	0.23			$	(0.41	)
Diluted:
Earnings (loss) per common unit from continuing operations	$	(0.12	)		$	0.18			$	0.23			$	(0.42	)
Earnings (loss) per common unit from discontinued operations	—				(0.02		)		—				(0.10		)
Diluted earnings (loss) per common unit	$	(0.12	)		$	0.16			$	0.23			$	(0.52	)
Weighted average number of common units outstanding - basic (1)	31,034,186				30,270,572				31,233,523				30,120,216
Weighted average number of common units outstanding - diluted (1)	31,034,186				30,400,584				31,371,152				30,183,091
(1) See Note 8.

 

See accompanying notes to unaudited condensed consolidated financial statements.

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EMERGE ENERGY SERVICES LP

UNAUDITED CONDENSED CONSOLIDATED STATEMENT OF PARTNERS’ EQUITY

($ in thousands)

 

	Limited Partner Common Units				General Partner (non-economic  interest)				Total Partners’ Equity
Balance at December 31, 2017	$	49,109			$	—			$	49,109
Net income	7,061				—				7,061
Equity-based compensation	1,224				—				1,224
Issuance of equity	5,974				—				5,974
Other	(60		)		—				(60		)
Balance at September 30, 2018	$	63,308			$	—			$	63,308

 

See accompanying notes to unaudited condensed consolidated financial statements.

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EMERGE ENERGY SERVICES LP

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

($ in thousands) 

	Nine Months Ended September 30,
	2018				2017
Cash flows from operating activities:
Net income (loss)	$	7,061			$	(12,458	)
Adjustments to reconcile net income (loss) to net cash flows from operating activities:
Depreciation, depletion and amortization	15,532				16,409
Equity-based compensation expense	1,224				1,020
Project and contract termination costs	1,689				—
Unrealized (gain) loss on fair value of warrant	(1,899		)		(3,212		)
Write-down of escrow receivable	—				3,125
Provision for doubtful accounts	310				—
Loss (gain) on disposal of assets	424				79
Amortization of debt discount/premium and deferred financing costs	6,597				2,750
Unrealized (gain) loss on derivative instruments	—				(225		)
Other non-cash charges	91				83
Changes in operating assets and liabilities:
Accounts receivable	26,701				(31,881		)
Inventories	(4,729		)		(9,411		)
Prepaid expenses and other current assets	(6,568		)		2,713
Accounts payable and accrued liabilities	239				16,888
Other assets	1,718				233
Cash flows from operating activities	48,390				(13,887		)
Cash flows from investing activities:
Purchases of property, plant and equipment	(64,154		)		(5,439		)
Net proceeds from disposal of assets	834				211
Asset acquisition	—				(20,430		)
Cash flows from investing activities	(63,320		)		(25,658		)
Cash flows from financing activities:
Proceeds from line of credit borrowings	11,014				253,075
Proceeds from second lien notes	175,000				39,597
Repayment of line of credit borrowings	(154,714		)		(247,272		)
Repayment of other long-term debt	(5,882		)		—
Payment of business acquisition obligation	(1,361		)		(2,223		)
Payment of financing costs	(11,971		)		(3,024		)
Other financing activities	(60		)		(63		)
Cash flows from financing activities	12,026				40,090
Cash and cash equivalents:
Net increase (decrease)	(2,904		)		545
Balance at beginning of period	5,729				4
Balance at end of period	$	2,825			$	549

  See accompanying notes to unaudited condensed consolidated financial statements.

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EMERGE ENERGY SERVICES LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

1.               ORGANIZATION AND BASIS OF PRESENTATION  

Organization  

Emerge Energy Services LP (“Emerge”) is a Delaware limited partnership that completed its initial public offering (“IPO”) on May 14, 2013 to become a publicly traded partnership.  The combined entities of Superior Silica Sands LLC (“SSS”), a Texas limited liability company and Emerge Energy Services Operating LLC (“Emerge Operating”), a Delaware limited liability company, currently represent Emerge. 

References to the “Partnership,” “we,” “our” or “us” refer collectively to Emerge and all of its subsidiaries.

We are engaged in the business of mining, processing, and distributing silica sand, a key input for the hydraulic fracturing of oil and gas wells. We conduct our operations through our subsidiary SSS, and we believe our Superior Silica Sands brand has name recognition and a positive reputation with our customers. The Sand business conducts mining and processing operations from facilities located in Wisconsin and Texas.  In addition to mining and processing silica sand for the oil and gas industry, the Sand business sells its product for use in building products and foundry operations. 

We previously owned a fuel business that operated transmix processing facilities located in the Dallas-Fort Worth area and in Birmingham, Alabama.  The Fuel business also offered third-party bulk motor fuel storage and terminal services, biodiesel refining, sale and distribution of wholesale motor fuels, reclamation services (which consists primarily of cleaning bulk storage tanks used by other petroleum terminal and others) and blending of renewable fuels. 

Basis of Presentation and Consolidation  

The accompanying unaudited condensed consolidated financial statements were prepared using generally accepted accounting principles for interim financial information and the instructions to Form 10-Q and Regulation S-X. Accordingly, these financial statements do not include all information or notes required by generally accepted accounting principles for annual financial statements and should be read together with our  2017  Annual Report on Form 10-K. These financial statements include the accounts of all of our subsidiaries. All significant intercompany transactions and balances have been eliminated in consolidation. In the opinion of management, all adjustments and disclosures necessary for a fair presentation of these interim statements have been included.

2.               ASSET ACQUISITIONS

Oklahoma

On May 11, 2018, we signed a 25 -year lease deal for the mining rights to approximately 600 acres located in Kingfisher County, Oklahoma, about 60 miles northwest of Oklahoma City. We purchased 40 acres of land adjoining the leased acreage on which to construct wet and dry processing plants expected to have a capacity of 1.5 million tons per year. This facility will serve the Mid-Continent region. We began construction in the third quarter, with production anticipated to come online in early 2019. The site is connected to a highway and has close proximity to railway, which could facilitate product shipment if we choose to develop rail loadout infrastructure.

San Antonio

On April 12, 2017, we closed the transaction to acquire substantially all of the assets of Materials Holding Company, Inc., Osburn Materials, Inc., Osburn Sand Co. and South Lehr, Inc. for  $20 million . The transaction was funded with a $40 million  term loan. The San Antonio site is located 25 miles south of San Antonio, Texas, and previously produced and sold construction, foundry and sports sands, but did not serve the energy markets. We upgraded the existing operations for conversion into frac sand production and commenced frac sand production in July 2017. Our San Antonio site’s reserves consist mostly of 40/70 and 100 mesh sands and meet American Petroleum Institute (“API”) specifications for all grades.

We early adopted the provisions of Accounting Standards Codification (“ASC”) 805,  Business Combinations and Accounting Standards Update (“ASU”) 2017-01,  Business Combinations (Topic 805): Clarifying the Definition of a Business , in accounting for this transaction. Under this guidance, if substantially all of the fair value of the gross assets acquired is concentrated in a single asset or group of similar assets, the transaction can be accounted for as an asset purchase. Based on our analysis of the transaction, substantially all of the fair value is concentrated in the sand reserves acquired, and thus we accounted for the transaction as an asset purchase. Significant judgment is often required in estimating the fair values of assets acquired. We engaged a third-party valuation specialist in estimating fair values of the assets acquired. We used our best estimates and assumptions to allocate the cost of the

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acquisition to the assets acquired on a relative fair value basis at the acquisition date. The fair value estimates are based on available historical information and on expectations and assumptions about the future production and sales volumes, market demands, the average selling price of sand, and the discount factor used in estimating future cash flows. While we believe those expectations and assumptions are reasonable, they are inherently uncertain. Transaction costs of $434,000 incurred for the acquisition are capitalized as a component of the cost of the assets acquired.

3.               OTHER FINANCIAL DATA  

Adoption of ASC 606, Revenue from Contracts with Customers

In May 2014, the Financial Accounting Standards Board (“FASB”) issued ASU 2014-09, Revenue from Contracts with Customers , ASC 606. The new revenue recognition standard provides a five-step analysis of transactions to determine when and how revenue is recognized. The core principle is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. It also requires entities to disclose both quantitative and qualitative information that enable financial statements users to understand the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. ASC 606 replaced most existing revenue recognition guidance in United States Generally Accepted Accounting Principles (“GAAP”) when it became effective for fiscal years beginning after December 15, 2017. ASC 606 permits the use of either the retrospective or cumulative effect transition method. We conducted and completed a comprehensive review of contracts and their associated business terms and conditions and performed detailed analyses on the impact of this standard to our contracts. We adopted the new standard on January 1, 2018, using the full retrospective method. Because accounting for revenue under contracts did not materially change for us under the new standard as explained below, prior period consolidated financial statements did not require adjustment.

We recognize revenue at a point in time when obligations under the terms of a contract with our customer are satisfied. This occurs with the transfer of control of our products to customers when products are shipped for direct sales to customers or when the product is picked up by a customer either at our plant location or transload location. Our contracts contain one performance obligation which is the delivery of sand to the customer at a point in time. Revenue is measured as the amount of consideration we expect to receive in exchange for transferring products. We recognize the cost for shipping as an expense in cost of sales when control over the product has transferred to the customer. Sales taxes collected concurrently with revenue-producing activities are excluded from revenue.

Our sand products are sold to United States and Canada-based customers primarily in the energy industry. Demand for our product is impacted by the economic conditions related to the energy industry, particularly fluctuations in oil and gas prices. This affects the nature, amount, timing and uncertainty of our revenue. Changes in the price of oil and gas relative to other inflationary measures could make our products more or less affordable and therefore affect our sales. We also sell a small quantity of non-frac sand to customers outside the energy industry.

Our payment terms vary by type and location of our customers. In most cases, the term between invoicing and the payment due date is 30 days. For certain customers, we require payment before the product is delivered.

The following tables present our revenues disaggregated by nature of product for the three and nine months ended September 30, 2018 , and 2017 :

	Three Months Ended September 30,
	2018							2017
	$ in Thousands				Tons in Thousands			$ in Thousands				Tons in Thousands
Frac sand revenues	$	61,597			985			$	101,795			1,361
Non-frac sand revenues	1,364				88			1,420				119
Total revenues	$	62,961			1,073			$	103,215			1,480

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	Nine Months Ended September 30,
	2018							2017
	$ in Thousands				Tons in Thousands			$ in Thousands				Tons in Thousands
Frac sand revenues	$	268,356			3,941			$	258,055			3,890
Non-frac sand revenues	3,197				224			3,106				233
Total revenues	$	271,553			4,165			$	261,161			4,123

We maintain an allowance for doubtful accounts to reflect estimated losses resulting from the failure of customers to make required payments. On an ongoing basis, the collectability of accounts receivable is assessed based upon historical collection trends, current economic factors and the assessment of the collectability of specific accounts. We evaluate the collectability of specific accounts and determine when to grant credit to our customers using a combination of factors, including the age of the outstanding balances, evaluation of customers’ current and past financial condition, recent payment history, current economic environment, and discussions with our personnel and with the customers directly. Accounts are written off when it is determined the receivable will not be collected. If circumstances change, our estimates of the collectability of amounts could change by a material amount.

A limited number of our contracts have variable consideration, including shortfall fees and demurrage fees. For a limited number of customers, we sell under long-term, minimum purchase supply agreements. These agreements define, among other commitments, the volume of product that our customers must purchase, the volume of product that we must provide, and the price that we will charge for each product. The shortfall fees are billed when the customer does not meet the minimum purchases over a period of time defined in each contract. As we do not have the ability to predict the customer’s orders over the period, there are constraints around our ability to recognize the variability in consideration related to this condition. Demurrage fees are assessed to customers for not returning the railcar timely and according to the terms of the contract. Estimation of demurrage fees is also constrained as we cannot estimate when the customer will pick up the product from the railcar upon delivery. Shortfall fees and demurrage represent an immaterial amount of revenue historically. For these contracts we estimate our position quarterly using the most likely outcome method, including customer-provided forecasts and historical buying patterns, and we accrue for any asset or liability these arrangements may create. The effect of accruals for variable consideration on our consolidated financial statements is immaterial.

After a thorough and extensive analysis of all of our long-term, minimum purchase supply agreements and a review of the standard terms of the purchase orders, we determined that there is no material change in the transaction price and amounts allocated to performance obligations, or the timing of satisfaction of performance obligations under ASC 606 compared to our accounting for these items in previous periods.

Discontinued Operations

On August 31, 2016, we completed the sale of our Fuel business pursuant to the terms of the Fuel Business Purchase Agreement. The purchase price was $167.7 million , subject to adjustment based on actual working capital conveyed at closing. The following escrow accounts were established at closing:

•	$7 million of the sales price was withheld as a general escrow associated with certain indemnification obligations. Any unutilized escrow balance, plus any accrued interest thereon, will be paid 54 months from the closing date.

•	$4 million of the sales price was withheld as a hydrotreater escrow to satisfy any cost overruns of the Birmingham hydrotreater completion. In 2017, we wrote off the entire receivable relating to hydrotreator completion delays and cost overruns.

•	$2.25 million of the sales price was withheld as the Renewable Fuel Standard escrow account. The entire amount, along with interest thereon, was collected in April 2017.

•	$1 million of the sales price was withheld as a pipeline escrow account. Any unutilized escrow balance, along with any accrued interest thereon, will be released with the general escrow.

Escrow receivables are recorded at the net present values of estimated future recoveries and will be adjusted as contingencies are resolved.

During the nine months ended September 30, 2017 , we wrote off a non-cash charge of $3.1 million of the hydrotreator and pipeline escrow receivables relating to completion delays and cost overruns.

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Private Placement

In connection with our private placement in August 2016, we issued to the purchaser a warrant to purchase approximately 890,000 common units at an exercise price of $10.82 per common unit. The warrant, which expires on August 16, 2022, was exercisable immediately upon issuance and contains a cashless exercise provision and other customary provisions and protections, including anti-dilution protections. This warrant is classified as a liability in accordance with ASC 480, Distinguishing Liabilities from Equity, and is included in Other long-term liabilities on our Condensed Consolidated Balance Sheets. This warrant has not been exercised as of  September 30, 2018 .

Allowance for Doubtful Accounts  

The allowance for doubtful accounts totaled $327 thousand at September 30, 2018 , and $17 thousand at December 31, 2017 .

Inventories  

Inventories consisted of the following:  

	September 30, 2018				December 31, 2017
	($ in thousands)
Sand work in process	$	22,012			$	14,650
Sand finished goods	10,471				12,914
Sand raw materials and supplies	71				261
Total	$	32,554			$	27,825

 

Prepaid expenses and other current assets

Prepaid expenses and other current assets consisted of the following:  

	September 30, 2018				December 31, 2017
	($ in thousands)
Prepaid services	$	6,071			$	1,011
Prepaid lease assets, current (1)	2,251				2,496
Prepaid transload services	1,888				1,274
Prepaid insurance	1,231				875
Other	1,458				675
Total	$	12,899			$	6,331

(1)	The cost to transport leased railcars from the manufacturer to our site for initial placement in service is capitalized and amortized over the term of the lease (typically  five  to  seven  years). This balance reflects the current portion of these capitalized costs.

Property, Plant and Equipment  

Property, plant and equipment consisted of the following:  

	September 30, 2018				December 31, 2017
	($ in thousands)
Machinery and equipment (1)	$	99,849			$	92,353
Buildings and improvements (1)	94,115				66,444
Mineral reserves	49,091				49,091
Land and improvements (1)	48,273				45,567
Construction in progress	34,170				15,696
Capitalized reclamation costs	2,521				2,521
Total cost	328,019				271,672
Accumulated depreciation and depletion	98,146				85,702
Net property, plant and equipment	$	229,873			$	185,970

(1) Includes assets under capital lease .

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We recognized $14.2 million and $14.1 million of depreciation and depletion expense for the nine months ended September 30, 2018 , and 2017 , respectively.

We capitalize a portion of the interest on funds borrowed to finance the construction of our plants. During the three and nine months ended September 30, 2018 , we capitalized $0.6 million and $1.7 million of interest for the construction of the San Antonio facility.

Intangible Assets

Our intangible assets consisted of the following:

	Cost				Accumulated  Amortization				Net
	($ in thousands)
September 30, 2018:
Non-compete agreement	$	100			$	42			$	58
December 31, 2017:
Patents	$	7,443			$	6,188			$	1,255
Supply and transportation agreements	569				226				343
Non-compete agreement	100				34				66
Total	$	8,112			$	6,448			$	1,664

We recognized $1.3 million and $2.3 million of amortization expense for the nine months ended September 30, 2018 , and 2017 , respectively.  

Other Assets, Net  

Other assets, net consisted of the following:

	September 30, 2018				December 31, 2017
	($ in thousands)
Deferred lease asset (1)	$	8,727			$	8,775
Prepaid lease assets, net of current portion (2)	5,963				7,153
Escrow receivable, non-current (3)	5,953				5,684
Other	465				2,810
Total	$	21,108			$	24,422

(1)

During 2016, we completed negotiations with various railcar lessors pursuant to which we terminated future orders of railcars, deferred future railcar deliveries and reduced and deferred payments on existing leases. The cost of deferring future railcar deliveries was recorded as a deferred lease asset. This asset will be amortized over the terms of the associated leases as those railcars enter service.

(2)	The cost to transport leased railcars from the manufacturer to our site for initial placement in service is capitalized and amortized over the term of the lease (typically five to seven years). This balance reflects the non-current portion of these capitalized costs.

(3)	Non-current receivables are recorded at net present value of estimated recoveries and will be adjusted as contingencies are resolved.

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Accrued Liabilities  

Accrued liabilities consisted of the following:

	September 30, 2018				December 31, 2017
	($ in thousands)
Mining	$	3,461			$	170
Logistics	3,202				5,898
Fuel sale related liabilities	2,483				2,475
Construction	1,327				7,122
Sales, excise, property and income taxes	1,269				1,953
Current portion of business acquisition obligations	1,255				1,952
Salaries and other employee-related	860				4,633
Deferred compensation	848				848
Accrued interest	367				2,552
Professional fees	273				373
Sand purchases and royalties	258				311
Current portion of contract termination	85				210
Other	790				1,221
Total	$	16,478			$	29,718

Other Long-term Liabilities

Other long-term liabilities consisted of the following:

	September 30, 2018				December 31, 2017
	($ in thousands)
Deferred lease obligation (1)	$	11,000			$	9,561
Long-term promissory note	3,376				9,370
Asset retirement obligation	2,800				2,792
Warrants	912				2,811
Contract and project terminations	891				5,348
Total	$	18,979			$	29,882

(1)	We recognize lease expense for operating leases on a straight-line basis over the term of the lease, beginning on the date we take possession of the property. The difference between the cash paid to the lessor and the amount recognized as lease expense on a straight-line basis is included in deferred lease obligation.

Long-term Promissory Note

During the second quarter of 2016, we negotiated significant concessions on the majority of our railcar leases pursuant to which we cancelled or deferred deliveries on railcars and reduced cash payments on a substantial portion of the existing railcars in our fleets. In exchange for these concessions, we issued at par an unsecured promissory note in the aggregate principal amount of $8 million (the “PIK Note”) for delivery deferrals. The PIK Note bears interest at a rate of 10% per annum payable in cash or, in certain situations, in-kind, when certain financial metrics have been met. We began paying interest in cash as of January 1, 2018. The PIK Note will mature on June 2, 2020. We paid  $1.5 million  of the principal balance in January 2018, as part of our debt refinancing described in Note 4 to our Condensed Consolidated Financial Statements. We also issued warrants to purchase 370,000 common units representing limited partnership interests in the Partnership in exchange for these concessions during the second quarter of 2016.

Contract and Project Terminations

In December 2015, we gained access to a significant reserve base in Jackson County, Wisconsin through a business arrangement with a contracted customer. The assets acquired included certain owned and leased land, sand deposit leases and related prepaid royalties, and transferable mining and reclamation permits. In consideration for the assets, we amended and restated the existing supply agreement between the parties and entered into a new sand purchase option agreement that provided the customer with a

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market-based discount on sand purchased from us. Under the agreements, we have the option to supply the contracted tons from our existing footprint of northern white sand operations or construct a new sand mine and dry plant in Jackson County, Wisconsin. Due to changing market conditions and changing preferences of customer demand, we determined that these projects were no longer economically viable and decided to terminate the land owner agreements and the mine permits. We recorded a $1.9 million charge to earnings to write off the related prepaid royalties during the nine months ended September 30, 2018 . As we terminated our permits for these properties, we will not owe any future royalty payments related to these properties.

During 2016, we negotiated concessions on the majority of our railcar leases pursuant to which we cancelled or deferred deliveries on railcars and reduced cash payments on a substantial portion of the existing railcars in our fleets. In exchange for these concessions, we incurred a contract termination charge of $4 million . We issued at par an unsecured promissory note in the aggregate principal amount of $4 million with interest payable in cash or, in certain situations, in-kind, when certain financial metrics have been met. This note bore interest at a rate of five percent per annum. We fully extinguished this liability and paid $4.4 million in January 2018 as part of our debt refinancing described in Note 4 to our Condensed Consolidated Financial Statements.

The following table illustrates the various contract termination liabilities and exit and disposal reserves included in Accrued liabilities and Other long-term liabilities in our Condensed Consolidated Balance Sheets:

	($ in thousands)
Balance at December 31, 2017	$	5,557
Adjustments	(221		)
Accretion	22
Payments	(4,382		)
Balance at September 30, 2018	$	976

Mining and Wet Sand Processing Agreement

In April 2014, a five -year contract with a sand processor (“Processor”) became effective to support our Sand business in Wisconsin. In January 2015, the agreement was amended and extended to expire on December 31, 2021. Under this contract, the Processor financed and built a wet wash processing plant near our Wisconsin operations. As part of the agreement, the Processor wet washes our sand, creates stockpiles of washed sand and maintains the plant and equipment. During the term of the agreement the Processor will own the wet plant along with the equipment and other temporary structures used to support this activity. At the end of the term of the agreement or following a default under the contract by the Processor, we have the right to take ownership of the wet plant and other equipment without charge. Subject to certain conditions, ownership of the plant and equipment will transfer to us at the expiration of the term. We accounted for the wet plant as a capital lease obligation.

Fair Value Measurements

Our financial instruments consist primarily of cash and cash equivalents, accounts receivable, accounts payable and debt instruments.  The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable are representative of their fair values due to their short maturities.  The carrying amounts of our revolving credit facility approximates fair value because the underlying instrument includes provisions that adjust our interest rates based on current market rates.   The fair values of our other long-term liabilities are not materially different from their carrying values.

On August 8, 2016, we, as part of the private placement described above, also issued a warrant to the purchaser to purchase approximately 890,000 common units at an exercise price of $10.82 per common unit. This warrant shall be exercisable for a period of six years from the closing date and include customary provisions and protections, including anti-dilution protections. The fair value of this warrant at issuance date was calculated at $5.56 per unit based on a Black Scholes valuation model, utilizing Level 2 inputs based on the hierarchy established in ASC 820, Fair Value Measurement. This liability is  marked to market each quarter with fair value gains and losses recognized immediately in earnings and included in Other income (expense) on our Consolidated Statements of Operations. The warrant liability was $0.9 million and $2.8 million at September 30, 2018 , and December 31, 2017 , respectively. We recorded a non-cash mark-to-market gain of $1.5 million and $1.9 million during the three and nine months ended September 30, 2018 , and a gain of $0.9 million and $3.2 million during the three and nine months ended September 30, 2017 .

Retirement Plan  

We sponsor a 401(k) plan for substantially all employees that provides for us to match 100% of participant contributions up to 5% of the participant’s pay.  Additionally, we can make discretionary contributions as deemed appropriate by management. 

As of May 1, 2017, we reestablished the employer 401(k) contributions, which was previously suspended on July 1, 2016. Employer contributions to these plans totaled $0.7 million and $0.3 million for the nine months ended September 30, 2018 , and 2017 , respectively.

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Seasonality  

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

Concentration of Credit Risk  

We provide credit, in the normal course of business, to customers located throughout the United States and Canada.  We encounter a certain amount of credit risk as a result of a concentration of receivables among a few significant customers. We perform ongoing credit evaluations of our customers and generally do not require collateral.  The trade receivables (as a percentage of total trade receivables) as of September 30, 2018 , and December 31, 2017 , from such significant customers are set forth below:

	September 30, 2018			December 31, 2017
Customer A	20	%		*
Customer B	18	%		17	%
Customer C	12	%		*
Customer D	12	%		20	%
Customer E	*			13	%

An asterisk indicates trade receivables less than ten percent.

Significant customers

The table shows the percent of revenue of our significant customers for our continuing operations represented for the nine months ended September 30, 2018 and 2017 .

	September 30, 2018			September 30, 2017
Customer B	26	%		17	%
Customer D	13	%		*
Customer A	12	%		21	%
Customer E	*			10	%

An asterisk indicates revenue is less than ten percent.

Geographical Data  

Although we own no long-term assets outside the United States, we began selling sand in Canada during 2013.  We recognized $24.8 million and $15.9 million of revenues in Canada for the nine months ended September 30, 2018 , and 2017 , respectively.  All other sales have occurred in the United States.

Recent Issued Accounting Pronouncement  

In February 2016, the FASB issued ASU 2016-02, Leases. This ASU requires lessees to recognize lease assets and lease liabilities generated by contracts longer than a year on their balance sheets. The ASU also requires companies to disclose in the footnotes to their financial statements information about the amount, timing, and uncertainty for the payments they make for the lease agreements. ASU 2016-02 is effective for public companies for annual periods and interim periods within those annual periods beginning after December 31, 2018. In July 2018, the FASB issued ASU No. 2018-11, “Leases (Topic 842): Targeted Improvements”, which simplifies the implementation by allowing entities the option to instead apply the provisions of the new guidance at the effective date, without adjusting the comparative periods presented. We currently have significant long-term operating leases for railcars and other assets. Pursuant to the adoption, we will record substantial liabilities and corresponding assets for these leases. We are working with our independent consultant to assist us in our assessment of our lease contracts. Many factors will impact the ultimate measurement of the lease obligation to be recognized upon adoption. We continue to evaluate the impact this guidance will have on our consolidated financial statements. We expect to take advantage of the transition relief provided by the amendment to ASU 2016-02 which allows us to elect not to restate 2017 and 2018 comparative periods upon adoption and continue to apply ASC 840 to such periods. With respect to the available practical expedients, we expect to elect the primary package of expedients whereby we will reassess neither the existence, nor the classification nor the amount and

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treatment of initial direct costs of existing leases. We do not expect to apply hindsight to the evaluation of lease options (e.g., renewal) and, accordingly, do not expect to utilize the practical expedient that would allow such an approach. Finally, we plan to elect the expedient to not separate the lease components from the non-lease components for most lease arrangements. We have selected a lease accounting system, and our implementation of it is underway. While we are not yet in a position to assess the full impact of the application of this ASU, we expect that the impact of recording the lease liabilities and the corresponding additional assets will have a significant impact on our financial position and results of operations and related disclosures in the notes to our consolidated financial statements. We will adopt this guidance on January 1, 2019.

In August 2018, the FASB issued ASU 2018-15, Intangibles-Goodwill and Other-Internal-Use Software. The new guidance requires a customer in a cloud computing arrangement (i.e., hosting arrangement) that is a service contract to follow the internal-use software guidance in ASC 350-40 to determine which implementation costs to capitalize as assets or expense as incurred. Capitalized implementation costs related to a hosting arrangement that is a service contract will be amortized over the term of the hosting arrangement, beginning when the module or component of the hosting arrangement is ready for its intended use. The update is effective for calendar-year public business entities in 2020. For all other calendar-year entities, it is effective for annual periods beginning in 2021 and interim periods in 2022. Early adoption is permitted. We are currently evaluating the effect that the guidance will have on our financial statements and related disclosures.

4.                LONG-TERM DEBT  

Following is a summary of our long-term debt:  

	September 30, 2018				December 31, 2017
	($ in thousands)
Second lien term loan - principal	$	215,000			$	40,000
Revolving credit facility - principal	—				143,700
Less: Deferred financing costs, net	(18,696		)		(7,349		)
Total debt	196,304				176,351
Less current portion	(13,438		)		—
Long-term debt	$	182,866			$	176,351

Revolving Credit Facility  

On January 5, 2018, we entered into a $75.0 million Second Amended and Restated Revolving Credit and Security Agreement (the “Credit Agreement”), among the Partnership, as parent guarantor, each of its subsidiaries, as borrowers, PNC Bank, National Association (“PNC Bank”), as administrative agent and collateral agent, and the other lenders party thereto. The Credit Agreement replaced the Prior Credit Agreement. The Credit Agreement provides for a $75.0 million asset-based revolving credit facility, and a $20.0 million sublimit for the issuance of letters of credit. The Credit Agreement matures on January 5, 2022. Substantially all our assets are pledged as collateral on a first lien basis. This revolving credit facility is available to (i) refinance existing indebtedness, (ii) fund fees and expenses incurred in connection with the credit facility and (iii) for general business purposes, including working capital requirements, capital expenditures, permitted acquisitions, making debt payments when due, and making distributions and dividends.

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

•	a minimum liquidity requirement of $20.0 million at all times;

•	beginning with the fiscal quarter ending March 31, 2018, a total leverage ratio of a maximum of 5.50 :1.00 decreasing quarterly thereafter to 3.00 :1.00 for the fiscal quarter ending December 31, 2018, and thereafter;

•	beginning with the fiscal quarter ending March 31, 2018, a minimum fixed charge coverage ratio of 1.10 :1.00; and

•	a limit on capital expenditures, subject to certain availability thresholds.

Loans under the Credit Agreement bear interest at our option at either (i) a base rate, 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 0.75% to 1.25% based on total leverage ratio; or (ii) LIBOR plus an applicable margin ranging from 1.75% to 2.25% based on the Partnership’s total leverage ratio.

During the nine months ended September 30, 2018 , we wrote off $3.9 million of deferred financing costs relating to the reduction of our revolving credit facility.

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At September 30, 2018 , we did not have any outstanding borrowings under the Credit Agreement. Our weighted average interest rate for all borrowings under the Credit Agreement was 10.8% for the three months ended September 30, 2018 .

Second Lien Note Purchase Agreement

On January 5, 2018, the Partnership as guarantor, and the Partnership’s wholly owned subsidiaries Emerge Energy Services Operating LLC and Superior Silica Sands LLC, as issuers, entered into a $215.0 million Second Lien Note Purchase Agreement with HPS Investment Partners, LLC as notes agent and collateral agent (the “Second Lien Note Purchase Agreement”). The notes issued under the Second Lien Note Purchase Agreement will mature on January 5, 2023. Proceeds of the sale of the notes under the Second Lien Note Purchase Agreement will be used (i) to fully pay off the Partnership’s existing second lien term credit facility, (ii) to fully pay off the obligations under the Partnership’s Prior Credit Agreement, (iii) to finance capital expenditures, (iv) to pay fees and expenses incurred in connection with the new second lien facility and (v) for general business purposes. Substantially all of the Partnership’s assets are pledged as collateral on a second lien basis. 

The Second Lien Note Purchase Agreement contains various covenants and restrictive provisions and also requires the maintenance of certain financial covenants as follows: 

•	a minimum liquidity requirement of $20.0 million at all times;

•	beginning with the fiscal quarter ending March 31, 2018, a total leverage ratio of a maximum of 6.00 :1.00 decreasing quarterly thereafter to 3.00 :1.00 for the fiscal quarter ending March 31, 2019, and thereafter;

•	beginning with the fiscal quarter ending March 31, 2018, a minimum fixed charge coverage ratio of 1.10 :1.00, increasing quarterly to 2.00 :1.00 for the fiscal quarter ending March 31, 2019, and thereafter; and

•	a limit on capital expenditures, subject to certain availability thresholds.

Commencing on September 30, 2018, we are required to make quarterly principal payments (without premium or penalty) equal to (i) for each fiscal quarter ending on or prior to December 31, 2019, 1.25% , and (ii) for each fiscal quarter thereafter, 1.875% , of the original principal amount. Accordingly, on September 30, 2018 , we have classified $13.4 million of principal as a current liability.

The notes under the Second Lien Note Purchase Agreement bear interest at 11% per annum until December 31, 2018, and ranging from 10.00% per annum to 12.00% per annum thereafter, depending on the our leverage ratio.

In lieu of paying cash for certain transaction costs, we also issued 814,295 common units representing limited partnership interests in the Partnership to the Second Lien Note holders in a private placement in January 2018. Proceeds from this issuance, net of expenses, was $6.0 million .

Covenants Compliance

At September 30, 2018 , we were in compliance with our loan covenants and had undrawn availability under the Credit Agreement totaling $61.5 million , well above the minimum availability required under our current covenants. However, if in the future we are unable to comply with the financial covenants and the lenders are unwilling to provide us with additional flexibility or a waiver, it could result in a default, and we may be forced to repay or refinance amounts then outstanding under the Credit Agreement or the Second Lien Note Purchase Agreement and seek alternative sources of capital to fund our business and anticipated capital expenditures. Any such alternative sources of capital, such as equity transactions or debt financing, may be on terms less favorable or at higher costs than our current financing sources, depending on future market conditions and other factors, or may not be available at all.

5.               RELATED PARTY TRANSACTIONS  

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

	Nine Months Ended September 30,
	2018				2017
	($ in thousands)
Employee-related and other costs (1)	$	20,401			$	13,338

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	September 30, 2018				December 31, 2017
	($ in thousands)
Accounts receivable, net	$	97			$	962
Accounts payable and accrued liabilities	$	521			$	800

(1)	We do not have any employees.  Our general partner manages our human resource assets, including fringe benefits and other employee-related charges.  We routinely and regularly reimburse our general partner for any employee-related costs paid on our behalf, and report such costs as operating expenses.

The Company follows ASC 850,  Related Party Disclosures , for the identification of related parties and disclosure of related party transactions. In 2017, Mr. Paul Shearer, the son of our President and Chief Executive Officer, was hired as the Director of Business Relations and he currently serves as the Director of Sales.  During the nine months ended September 30, 2018 , we paid Paul Shearer $163 thousand in total compensation, including base salary, bonus, company contributions under our 401(k) plan and contributions to his health savings account.

6.               EQUITY-BASED COMPENSATION  

Effective May 14, 2013, we adopted our 2013 Long-Term Incentive Plan (the “LTIP”) for providing long-term incentives for employees, directors, and consultants who provide services to us. The LTIP provides for the issuance of an aggregate of up to 2,321,968 common units to be granted either as options, restricted units, phantom units, distribution equivalent rights, unit appreciation rights, unit award, profits interest units, or other unit-based award granted under the plan.  All of our outstanding grants will be settled through issuance of limited partner common units.

For remaining phantom units granted to employees in 2013, we currently assume a 67 -month vesting period, which represents management’s estimate of the amount of time until all vesting conditions have been met. For other phantom units granted to employees, we have a 24 to 36 -month vesting period. Restricted units are awarded to our independent directors on each anniversary of our IPO, each with a vesting period of one year.  Regarding distributions for independent directors and other employees, distributions are credited to a distribution equivalent rights account for the benefit of each participant and become payable generally within 45 days days following the date of vesting.  As of September 30, 2018 , the unpaid liability for distribution equivalent rights totaled $0.8 million . 

During the nine months of 2018, we granted 24,800 time-based phantom units to certain officers and employees to vest in equal installments on each anniversary date of the grant over a period of two years.

The following table summarizes awards granted during the nine months ended September 30, 2018 .  

	Total Units			Phantom Units			Restricted Units			Fair Value per Unit at Award Date
Outstanding at December 31, 2017	333,821			310,780			23,041			$	13.10
Granted	61,768			24,800			36,968			$	7.90
Vested	(53,656	)		(30,616	)		(23,040	)		$	13.44
Forfeitures	(2,000	)		(2,000	)		—			$	6.98
Outstanding at September 30, 2018	339,933			302,964			36,969			$	12.14

 

For the nine months ended September 30, 2018 , and 2017 , we recorded non-cash equity-based compensation expense of $1.2 million and $1.0 million , respectively, in selling, general and administrative expenses. 

As of September 30, 2018 , the unrecognized compensation expense related to the grants discussed above amounted to $1.0 million to be recognized over a weighted average of 0.8 years .

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7.               INCOME TAXES  

Our provision for income taxes relates to: (i) Texas margin taxes for the Partnership, and (ii) a Canadian income taxes on SSS earnings in Canada (most of our earnings are exempted under a U.S/Canada tax treaty).  For federal income tax purposes, we report our income, expenses, gains, and losses as a partnership not subject to income taxes.  As such, each partner is responsible for his or her share of federal and state income tax.  Net earnings for financial statement purposes may differ significantly from taxable income reportable to each partner because of differences between the tax basis and financial reporting basis of assets and liabilities.

The composition of our provision for income taxes is as follows:

	Nine Months Ended September 30,
	2018				2017
	($ in thousands)
Texas margin tax	$	128			$	(58	)
Canadian income tax	55				—
Total provision for income taxes	$	183			$	(58	)

 

We are responsible for our portion of the Texas margin tax that is included in our subsidiaries’ consolidated Texas franchise tax returns.  For our operations in Texas, the effective margin tax rate is approximately 0.375% as defined by applicable state law.  The margin tax qualifies as an income tax under GAAP, which requires us to recognize the impact of this tax on the temporary differences between the financial statement assets and liabilities and their tax basis attributable to such tax.

8.               EARNINGS PER COMMON UNIT  

We compute basic earnings (loss) per unit by dividing net income (loss) by the weighted-average number of common units outstanding including certain participating securities.  Participating securities include unvested equity-based payment awards that contain rights to distributions, as well as convertible preferred units and warrants that contain contractual rights to participate in any distributions that are declared.  It is our policy to exclude participating securities, convertible preferred units and warrants from the calculation of basic earnings (loss) per unit in periods of net losses from continuing operations since these securities are not contractually obligated to share in losses.

Diluted earnings per unit is computed by dividing net income by the weighted-average number of common units outstanding, including the number of common units that would have been outstanding had potential dilutive units been exercised.  The dilutive effect of restricted units is reflected in diluted net income per unit by applying the treasury stock method.  For periods in which warrants are dilutive, we reverse the income effects of the warrants and include incremental units in our computation of diluted earnings per unit. Under FASB ASC 260-10-45, Contingently Issuable Shares , 93,806 of our outstanding phantom units are not included in basic or diluted earnings per common unit calculations as of September 30, 2018 , and 2017 . 

Basic and diluted earnings per unit for the three months ended September 30, 2018 , and 2017 , is calculated as follows:

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	Continuing								Discontinued								Consolidated
	Three Months Ended September 30,
	2018				2017				2018				2017				2018				2017
	($ in thousands, except unit and per unit data)
Net income (loss)	$	(3,853	)		$	5,482			$	—			$	(468	)		$	(3,853	)		$	5,014
Weighted average common units outstanding	31,034,186				30,150,915				31,034,186				30,150,915				31,034,186				30,150,915
Weighted average units deemed participating securities	—				119,657				—				119,657				—				119,657
Weighted average number of common units outstanding - basic	31,034,186				30,270,572				31,034,186				30,270,572				31,034,186				30,270,572
Add incremental units from assumed exercise of warrants	—				130,012				—				130,012				—				130,012
Weighted average number of common units outstanding - diluted	31,034,186				30,400,584				31,034,186				30,400,584				31,034,186				30,400,584
Earnings (loss) per unit, basic	$	(0.12	)		$	0.19			$	—			$	(0.02	)		$	(0.12	)		$	0.17
Earnings (loss) per unit, diluted	$	(0.12	)		$	0.18			$	—			$	(0.02	)		$	(0.12	)		$	0.16

Basic and diluted earnings per unit for the nine months ended September 30, 2018 , and 2017  is calculated as follows:

	Continuing								Discontinued								Consolidated
	Nine Months Ended September 30,
	2018				2017				2018				2017				2018				2017
	($ in thousands, except unit and per unit data)
Net income (loss) used to compute earnings (loss) per common unit, basic	$	7,061			$	(9,333	)		$	—			$	(3,125	)		$	7,061			$	(12,458	)
Unrealized (gain) loss on fair value of warrant	—				(3,212		)		—				—				—				(3,212		)
Net income (loss) used to compute earnings (loss) per common unit, diluted	$	7,061			$	(12,545	)		$	—			$	(3,125	)		$	7,061			$	(15,670	)
Weighted average common units outstanding	31,020,310				30,120,216				31,020,310				30,120,216				31,020,310				30,120,216
Weighted average units deemed participating securities	213,213				—				213,213				—				213,213				—
Weighted average number of common units outstanding - basic	31,233,523				30,120,216				31,233,523				30,120,216				31,233,523				30,120,216
Weighted average potentially dilutive units outstanding	15,757				—				15,757				—				15,757				—
Add incremental units from assumed exercise of warrants	121,872				62,875				121,872				62,875				121,872				62,875
Weighted average number of common units outstanding - diluted	31,371,152				30,183,091				31,371,152				30,183,091				31,371,152				30,183,091
Earnings (loss) per unit, basic	$	0.23			$	(0.31	)		$	—			$	(0.10	)		$	0.23			$	(0.41	)
Earnings (loss) per unit, diluted	$	0.23			$	(0.42	)		$	—			$	(0.10	)		$	0.23			$	(0.52	)

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9.        RECURRING FAIR VALUE MEASUREMENTS

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

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

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

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

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

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

We do not designate our derivative instruments as hedges under GAAP.  As a result, we recognize derivatives at fair value on the consolidated balance sheet with resulting gains and losses reflected in interest expense (for interest rate swap agreements). Our derivative instruments serve the same risk management purpose whether designated as a hedge or not. We derive fair values principally from published market interest rates (Level 2 inputs). We do not use derivative financial instruments for trading or speculative purposes.  

On August 8, 2016, we, as part of the private placement described above, issued a warrant to the purchaser to purchase approximately 890,000  common units at an exercise price of  $10.82  per common unit. The warrant shall be exercisable for a period of  six years from the closing date and include customary provisions and protections, including anti-dilution protections. The fair value of this warrant at issuance date was calculated at  $5.56  per unit based on a Black Scholes valuation model, utilizing Level 2 inputs based on the hierarchy established in ASC 820, Fair Value Measurement.  This liability is  marked to market each quarter with fair value gains and losses recognized immediately in earnings and included in Other expense (income) on our Condensed Consolidated Statements of Operations. We recorded a non-cash mark-to-market gain of $1.5 million and $1.9 million during the three and nine months ended September 30, 2018 , and a non-cash mark-to-market gain of $0.9 million and $3.2 million during the three and nine months ended September 30, 2017 .

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

	September 30, 2018				December 31, 2017				Classification
	($ in thousands)
Warrant liability	$	912			$	2,811			Other long-term liabilities

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

	Three Months Ended September 30,								Nine Months Ended September 30,
	2018				2017				2018				2017				Classification
	((income) expense $ in thousands)
Interest rate swaps	$	—			$	2			$	—			$	(62	)		Interest expense, net
Warrant	(1,467		)		(900		)		(1,899		)		(3,212		)		Other expense (income)
	$	(1,467	)		$	(898	)		$	(1,899	)		$	(3,274	)

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10.        SUPPLEMENTAL CASH FLOW DISCLOSURES  

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

	Nine Months Ended September 30,
	2018				2017
	($ in thousands)
Cash paid for interest, net of capitalized interest	$	13,878			$	10,934
Cash paid for income taxes, net of refunds	$	28			$	(22	)
Issuance of equity	$	5,974			$	—
Purchases of PP&E accrued but not paid at period-end	$	7,670			$	1,432
Purchases of PP&E accrued in a prior period and paid in the current period	$	11,372			$	170

ITEM 2.                                                 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS  

Emerge Energy Services LP (“Emerge”) is a Delaware limited partnership that completed its initial public offering (“IPO”) on May 14, 2013 to become a publicly traded partnership.  The combined entities of Superior Silica Sands LLC (“SSS”), a Texas limited liability company and Emerge Energy Services Operating LLC (“Emerge Operating”), a Delaware limited liability company, currently represent Emerge. 

References to the “Partnership,” “we,” “our” or “us” refer collectively to Emerge and all of its subsidiaries.

Overview  

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

The following discussion analyzes our financial condition and results of operations and should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2017 , as well as historical condensed consolidated financial statements and notes included elsewhere in this Quarterly Report.  

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Results of Operations  

The following table summarizes our consolidated operating results:

	Three Months Ended September 30,								Nine Months Ended September 30,
	2018				2017				2018				2017
	($ in thousands)
Revenues	$	62,961			$	103,215			$	271,553			$	261,161
Operating expenses:
Cost of goods sold (excluding depreciation, depletion and amortization)	52,337				80,239				205,229				223,978
Depreciation, depletion and amortization	5,316				6,078				15,532				16,409
Selling, general and administrative expenses	3,693				7,302				19,654				20,030
Contract and project terminations	—				—				1,689				—
Total operating expenses	61,346				93,619				242,104				260,417
Operating income (loss)	1,615				9,596				29,449				744
Other expense (income):									—
Interest expense, net	6,907				5,073				24,135				13,353
Other	(1,472		)		(901		)		(1,930		)		(3,218		)
Total other expense	5,435				4,172				22,205				10,135
Income (loss) from continuing operations before provision for income taxes	(3,820		)		5,424				7,244				(9,391		)
Provision (benefit) for income taxes	33				(58		)		183				(58		)
Net income (loss) from continuing operations	(3,853		)		5,482				7,061				(9,333		)
Income (loss) from discontinued operations, net of taxes	—				(468		)		—				(3,125		)
Net income (loss)	$	(3,853	)		$	5,014			$	7,061			$	(12,458	)
Adjusted EBITDA (a)	$	7,927			$	18,743			$	48,675			$	26,345

(a)          See “Adjusted EBITDA” below for a discussion of Adjusted EBITDA and a reconciliation to net income (loss) and cash flows from operations.  

Major Factors Impacting Comparability Between Prior and Future Periods

Market Trends

The market for frac sand began to soften in early August 2018, due to a temporary decline in well completion activities as well as oil and natural gas exploration and production companies' budget exhaustions. These factors, along with the new production from in-basin frac sand competitors discussed below, led the sand market to quickly turn from a state of short supply in the first half of the year to oversupply in the last two months of the third quarter. As a result, the entire industry has experienced pricing pressure, particularly on the northern white product. This trend accelerated throughout September and is expected to continue through the rest of 2018. Based on industry outlooks from third-party research firms and customers, we expect conditions to improve in early 2019 as budgets are reset and demand and supply are better aligned.

Based on our 2019 outlook, we continue to enter into multi-year contracts with some of our key accounts. We are also executing take-or-pay sand supply agreements for our San Antonio operation and we are working on contracts with customers for Oklahoma. We believe that sand supply agreements ensure the customers a steady supply of product in exchange for covering fixed costs plus needed margins associated with operating our business.

Based on a shift in some customers’ preference for lower quality sand, our competitors have built in-basin frac sand operations targeting the Permian Basin in West Texas, the Eagle Ford Shale in South Texas, and Mid-Continent in Oklahoma.  There can be no assurances that all of the announced projects will be completed given permitting, construction, infrastructure, and environmental constraints. Our San Antonio operation positions us to target the second most active Texas in-basin market.

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Expansion of Sand Resources

On May 11, 2018, we signed a 25-year lease deal for the mining rights to approximately 600 acres located in Kingfisher County, Oklahoma, about 60 miles northwest of Oklahoma City. We purchased 40 acres of land adjoining the leased acreage on which to construct wet and dry processing plants expected to have a capacity of 1.5 million tons per year. This facility will serve the Mid-Continent region. We began construction in the third quarter and, with production anticipated to come online in early 2019. The site is connected to a highway and has close proximity to railway, which could facilitate product shipment if we choose to develop rail loadout infrastructure.

On April 12, 2017, we closed the transaction to acquire our San Antonio operations for $20 million. The San Antonio site is located approximately 25 miles south of San Antonio, Texas and previously produced and sold construction, foundry and sports sands, but did not serve the energy markets. We upgraded the existing operations for conversion into frac sand production and commenced frac sand production in July 2017. As part of our expansion strategy in San Antonio, we began construction of a new wet and dry plant on the site in October 2017. The new dry plant commenced operations in late April 2018. Full construction of the dry and wet plant is expected to be completed in the fourth quarter of 2018.  Our San Antonio reserves contain API-specification, strategic reserves (40/70 and100 mesh sands) that bolster our presence with in-basin local sands and balance our portfolio of northern white to local sands. With the close proximity of the plant to the Eagle Ford Shale, we expect to sell the majority of the sand produced at the plant into this shale play, which is currently the second most active in the United States.

Fixed Costs for Sand

We often enter into multi-year contracts with third parties for agreements that include railcar leases, transload terminal leases, and minimum volume mining contracts. During periods of business expansion, we typically enter into new arrangements with various third parties, or we increase commitments with existing third parties. During periods of business contraction, we work with our providers to lower our fixed cost obligations. We have achieved some success on reducing fixed costs during periods of business contraction, most notably during 2015 and 2016. In the second quarter we successfully deployed all of our railcars back into service. However, with the recent market shift from northern white sand and terminal sales, we have begun putting some railcars back into storage.

Changing Preferences of Customer Demand

For several years leading up to 2015, most oil and gas producers preferred the highest quality, coarsest grades of frac sand (20/40 and 30/50) to complete shale wells around North America. The drop in oil and gas prices during 2015 and 2016 forced many oil and gas producers to consider alternatives for lowering the cost to complete a new well. Lower quality proppants compared to northern white sands are often located closer to the shale basins than northern white sands, so some operators have elected to use these proppants and save on transportation costs. Finer mesh sands (40/70 and 100 mesh) have also been used more regularly as oil and gas well completion designs have evolved. Additionally, the amount of proppant pumped downhole per horizontal well continues to increase. As a leading provider of frac sand, we are able to meet the changing needs of our customers and the market. Our diversified set of capabilities enables us to produce both coarse and fine grades in large quantities. With our acquisition in San Antonio, we have two Texas operations that are well positioned geographically to meet the strong demand in the prolific Texas basins. Our new Kingfisher, Oklahoma site will allow us to serve customers in-basin for the Mid-Continent region.

Sand Distribution System

We have developed our sand distribution system over several years through the addition of third-party transload facilities in the basins in which our customers operate. We are able to charge higher prices for these terminal sales than for FOB plant sales to provide this additional service and convenience to our customers and to cover related transportation and other services costs.

Technology Driven Proppant Products

In early 2016, we launched our self-suspending sand marketed under the brand SandMaxX™. This new technology offers the potential to increase production in oil and gas wells in addition to improving pump time and reducing other upfront costs. Trial wells have proven that the technology is effective down-hole, but the customer adoption rate has been slower than initially anticipated. Under the contract, we had the option to continue ownership of this technology after the initial installment period (which expires on May 25, 2018) by payment of significant additional funds. Given the lack of market acceptance for SandMaxX™ proppant, even after considerable efforts to market the product, we have elected to discontinue ownership of the intellectual property after the initial installment period. This will not have a material impact on our financial position or results of operations.

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Continuing operations

	Three Months Ended September 30,								Nine Months Ended September 30,
	2018				2017				2018				2017
	($ in thousands)
Revenues:
Frac sand revenues	$	61,597			$	101,795			$	268,356			$	258,055
Non-frac sand revenues	1,364				1,420				3,197				3,106
Total revenues	62,961				103,215				271,553				261,161
Operating expenses:
Cost of goods sold (excluding depreciation, depletion and amortization)	52,337				80,239				205,229				223,978
Depreciation, depletion and amortization	5,316				6,078				15,532				16,409
Selling, general and administrative expenses	3,693				7,302				19,654				20,030
Contract and project terminations	—				—				1,689				—
Operating income (loss)	$	1,615			$	9,596			$	29,449			$	744
Net income (loss) from continuing operations	$	(3,853	)		$	5,482			$	7,061			$	(9,333	)
Adjusted EBITDA (a)	$	7,927			$	18,743			$	48,675			$	26,345
Volume of frac sand sold (tons in thousands)	985				1,361				3,941				3,890
Volume of non-frac sand sold (tons in thousands)	88				119				224				233
Total volume of sand sold (tons in thousands)	1,073				1,480				4,165				4,123
Terminal sand sales (tons in thousands)	247				671				1,249				1,803
Volume of frac sand produced by plant (tons in thousands):
Arland, Wisconsin facility	161				463				1,061				1,339
Barron, Wisconsin facility	353				497				1,360				1,547
New Auburn, Wisconsin facility	210				346				865				965
San Antonio, Texas facility (b)	223				16				391				16
Kosse, Texas facility	95				53				302				165
Total volume of frac sand produced	1,042				1,375				3,979				4,032

(a)          See “Adjusted EBITDA” below for a discussion of Adjusted EBITDA and a reconciliation to net income (loss) and operating cash flows.  

(b) We commenced frac sand production at the San Antonio facility in July 2017.

Three Months Ended September 30, 2018 Compared to Three Months Ended September 30, 2017

Revenues

Sand revenues decrease d by $40.3 million primarily due to a  28%   decrease  in total volumes sold driven by the decreased market demand for frac sand resulting from a temporary slow down in well completion activities. FOB plant sales volumes increased 2% compared to a 63% decrease in the higher-priced, terminal sand sales. Terminal sales as a percentage of total volumes sold decreased from 45% in 2017 to 23% in 2018. Revenue per ton decreased to $58.68 in 2018 compared to $69.74 per ton in 2017, due to lower northern white volumes sold, shift in mix away from higher-priced terminal sales and a decline in northern white prices.

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The major changes from 2017 to 2018 are as follows:

•	$20.3 million decrease in northern white sales (excluding estimated transportation markups), relating primarily to a 49% decrease in volumes sold, offset by $12.3 million increase of Texas sand sales mainly due to the addition of our San Antonio operation in July 2017; and

•	an estimated $32.3 million decrease in markups due to lower volumes sold through terminals.

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

Our cost of goods sold consists primarily of direct costs such as processing plant wages, royalties, mining, purchased sand, and transportation to the plant or to transload facilities, as well as indirect costs such as plant repairs and maintenance. Our direct costs of producing sand and our logistics costs for finished product decreased with our decreased sales. The most significant components of the $27.9 million   decrease from 2017 to 2018 are:

•	$22.1 million decrease in rail transportation-related expense, primarily due to decreased rail shipping costs resulting from decreased terminal sales volumes;

•	$4.2 million decrease in costs of transload facilities due to decreased volumes; and

•	$1.6 million decrease in the total cost to acquire and produce sand due to 28% decrease in total volumes sold, offset by higher start up costs for our San Antonio plant.

Selling, general and administrative expenses  

The $3.6 million decrease in selling, general and administrative expenses is attributable primarily to a decrease in employee-related costs mainly due to reduced bonus accruals in 2018.

Interest expense

Net interest expense increase d  $1.8 million primarily due to;

•	$4.9 million increase due to $175 million additional notes issued under the Second Lien Note Purchase Agreement; offset by

•	$2.5 million decreased interest expense due to the reduction of outstanding balances under the revolving credit facility; and

•	$0.6 million interest capitalized for the construction of the San Antonio plants.

Other

Other income increase d $0.6 million due to a higher mark-to-market net gain recognized in 2018 for a change in the fair value of the warrant issued in August 2016.

Nine Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2017

Revenues

Sand revenues increase d by $10.4 million , primarily due to higher prices of frac sand in 2018 compared to 2017, offset by lower terminal sales volumes. FOB plant sales volumes increase d 26% compared to a 31% decrease for the higher-priced terminal sand sales. Terminal sales as a percentage of total volumes sold decreased from 44% in the nine months of 2017 to 30% in the nine months of 2018. Revenue per ton increased to $65.20 in 2018 compared to $63.34 per ton in 2017 due to price increases, offset by a shift in mix between direct FOB plant sales and terminal sand sales.

The major changes from 2017 to 2018 are as follows:

•	$35.4 million increase in sales (excluding estimated transportation markups), relating primarily to improved pricing for frac sand, and addition of our San Antonio operation in July 2017; offset by

•	an estimated $25.1 million decrease in markups due to decreased terminal sales volumes.

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

Our cost of goods sold consists primarily of direct costs such as processing plant wages, royalties, mining, purchased sand, and transportation to the plant or to transload facilities, as well as indirect costs such as plant repairs and maintenance. Our logistics costs for finished product decreased due to lower terminal sales, offset by our increased direct costs of producing sand.  The most significant components of the $18.7 million decrease are:

•	$27.4 million decrease in rail transportation-related expense, primarily due to:

•	$26.0 million decreased rail shipping costs due to decreased terminal sales volumes sold and the shift in mix between direct FOB plant sales and terminal sand sales; and

•	$1.2 million decreased railcar storage costs as we had placed previously stored cars back into service.

•	$4.6 million decrease in costs of transload facilities due to decreased volumes, offset by

•	$13.2 million increase in the total cost to acquire and produce wet and dry sand, due mainly to higher startup costs at our San Antonio plant.

Selling, general and administrative expenses  

The $0.4 million decrease in selling, general and administrative expenses is attributable primarily to:

•	$2.7 million decrease in employee-related costs mainly due to reduced bonus accruals in 2018, and employee equity- based compensation; offset by

•	$1.1 million expenses related to the long-term debt refinancing in January 2018;

Interest expense

Net interest expense increase d  $10.8 million primarily due to:

•	$15.6 million increase due to a $215 million addition of the notes issued under the Second Lien Note Purchase Agreement; and

•	$3.9 million write-off of deferred financing costs relating to the reduction of our revolving credit facility in January 2018; offset by

•	$6.8 million decreased interest expense due to the reduction of outstanding balances under the revolving credit facility; and

•	$1.7 million interest capitalized for the construction of the San Antonio plants.

Other

Other income decrease d $1.3 million due to a lower mark-to-market net gain recognized in 2018 for a change in the fair value of the warrant issued in August 2016.

Contract and project terminations

During the three months ended March 31, 2018, we recorded a non-cash charge against earnings of $1.7 million. This charge relates to the write-off of prepaid royalties. See Note 3 to our Condensed Consolidated Financial Statements for further discussion.

Discontinued Operations

We completed the sale of our Fuel business on August 31, 2016, thus we do not have any operations for the Fuel business.

During the nine months ended September 30, 2017 , we wrote off a non-cash charge of $3.1 million of the hydrotreator and pipeline escrow receivables relating to completion delays and cost overruns.

Liquidity and Capital Resources  

Sources of Liquidity

Our principal liquidity requirements are to finance current operations, fund capital expenditures, finance acquisitions from time to time, service our debt and pay distributions to partners.  Our sources of liquidity generally include cash generated by our operations, borrowings under our revolving credit and security agreement and issuances of equity and debt securities.  We depend on the Credit Facility for both short-term and long-term capital needs and may use borrowings under our Credit Facility to fund our operations and capital expenditures to the extent cash generated by our operations is insufficient in any period. Following our entry into the Credit Agreement and the Second Lien Note Purchase Agreement (described below), we believe that cash generated

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from our liquidity sources will be sufficient to meet our working capital and capital expenditure needs for at least the next 12 months.

In addition to our continued focus on generating and preserving cash from operations and maintaining availability under the Credit Facility, we may seek access to the capital markets for additional liquidity through equity and debt offerings. Any new issuances may take the form of public or private offerings for cash, equity issued to consummate acquisitions or equity issued in exchange for a portion of our outstanding debt. We may also from time to time seek to retire or purchase outstanding debt through cash purchases and/or exchanges for equity or other debt securities, in open market purchases, privately negotiated transactions or otherwise. However, there can be no assurance that we will be able to complete any of these transactions on favorable terms or at all.

For 2018, we expect to spend between $80 million and $90 million in capital expenditures to fund the expansion of our San Antonio operation, Oklahoma construction, and finance various capital projects that offer attractive rates of return.

Revolving Credit Facility

On January 5, 2018, we entered into a $75.0 million Second Amended and Restated Revolving Credit and Security Agreement (the “Credit Agreement”), among the Partnership, as parent guarantor, each of its subsidiaries, as borrowers, PNC Bank, National Association (“PNC Bank”), as administrative agent and collateral agent, and the other lenders party thereto. The Credit Agreement replaced the Prior Credit Agreement. The Credit Agreement provides for a $75.0 million asset-based revolving credit facility, and a $20.0 million sublimit for the issuance of letters of credit. The Credit Agreement matures on January 5, 2022. Substantially all our assets are pledged as collateral on a first lien basis. This revolving credit facility is available to (i) refinance existing indebtedness, (ii) fund fees and expenses incurred in connection with the credit facility and (iii) for general business purposes, including working capital requirements, capital expenditures, permitted acquisitions, making debt payments when due, and making distributions and dividends.

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

•	a minimum liquidity requirement of $20.0 million at all times;

•	beginning with the fiscal quarter ending March 31, 2018, a total leverage ratio of a maximum of 5.50 :1.00 decreasing quarterly thereafter to 3.00 :1.00 for the fiscal quarter ending December 31, 2018, and thereafter;

•	beginning with the fiscal quarter ending March 31, 2018, a minimum fixed charge coverage ratio of 1.10 :1.00; and

•	a limit on capital expenditures, subject to certain availability thresholds.

Loans under the Credit Agreement bear interest at our option at either (i) a base rate, 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 0.75% to 1.25% based on total leverage ratio; or (ii) LIBOR plus an applicable margin ranging from 1.75% to 2.25% based on the Partnership’s total leverage ratio.

Second Lien Note Purchase Agreement

On January 5, 2018, the Partnership as guarantor, and the Partnership’s wholly owned subsidiaries Emerge Energy Services Operating LLC and Superior Silica Sands LLC, as issuers, entered into a $215.0 million Second Lien Note Purchase Agreement with HPS Investment Partners, LLC as notes agent and collateral agent (the “Second Lien Note Purchase Agreement”). The notes issued under the Second Lien Note Purchase Agreement will mature on January 5, 2023. Proceeds of the sale of the notes under the Second Lien Note Purchase Agreement will be used (i) to fully pay off the Partnership’s existing second lien term credit facility, (ii) to fully pay off the obligations under the Partnership’s Prior Credit Agreement, (iii) to finance capital expenditures, (iv) to pay fees and expenses incurred in connection with the new second lien facility and (v) for general business purposes. Substantially all of the Partnership’s assets are pledged as collateral on a second lien basis. 

The Second Lien Note Purchase Agreement contains various covenants and restrictive provisions and also requires the maintenance of certain financial covenants as follows: 

•	a minimum liquidity requirement of $20.0 million at all times;

•	beginning with the fiscal quarter ending March 31, 2018, a total leverage ratio of a maximum of 6.00 :1.00 decreasing quarterly thereafter to 3.00 :1.00 for the fiscal quarter ending March 31, 2019, and thereafter;

•	beginning with the fiscal quarter ending March 31, 2018, a minimum fixed charge coverage ratio of 1.10 :1.00, increasing quarterly to 2.00 :1.00 for the fiscal quarter ending March 31, 2019, and thereafter; and

•	a limit on capital expenditures, subject to certain availability thresholds.

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Commencing on September 30, 2018, we are required to make quarterly principal payments (without premium or penalty) equal to (i) for each fiscal quarter ending on or prior to December 31, 2019, 1.25%, and (ii) for each fiscal quarter thereafter, 1.875%, of the original principal amount. Accordingly, on September 30, 2018 , we have classified $13.4 million of principal as a current liability.

The notes under the Second Lien Note Purchase Agreement bear interest at 11% per annum until December 31, 2018, and ranging from 10.00% per annum to 12.00% per annum thereafter, depending on the our leverage ratio.

Covenants Compliance

At September 30, 2018 , we were in compliance with our loan covenants.

Liquidity Trends

In recent years, market prices for oil and natural gas have been highly volatile and have seen periods of downward pricing pressure. Although drilling and completion activity has improved significantly in the last two years, our cash flows from operating activities are subject to significant quarterly variations, as volatile commodity prices influence demand for our frac sand. Increased production from competitors can also potentially affect demand for our frac sand. Cash generated by our operations are thus driven by a number of factors beyond our control, including global and regional product supply and demand, weather, product distribution and refining and processing capacity and other supply chain dynamics, among other factors. As a result, our liquidity needs may not be met solely by cash generated from operations, and we expect to continue relying on borrowings under the Credit Agreement as source of future liquidity.

Furthermore, our ability to comply with the restrictions and covenants of the Credit Agreement and the Second Lien Note Purchase Agreement is uncertain and will be affected by the amount of cash flow from our operations and events or circumstances beyond our control, including events and circumstances that may stem from the condition of financial markets and commodity price levels. We are currently in compliance with the financial covenants under the Credit Agreement and the Second Lien Note Purchase Agreement. However, if in the future we are unable to comply with the financial covenants and the lenders are unwilling to provide us with additional flexibility or a waiver, it could result in a default, and we may be forced to repay or refinance amounts then outstanding under the Credit Agreement or the Second Lien Note Purchase Agreement and seek alternative sources of capital to fund our business and anticipated capital expenditures. Any such alternative sources of capital, such as equity transactions or debt financing, may be on terms less favorable or at higher costs than our current financing sources, depending on future market conditions and other factors, or may not be available at all. Please see “Risk Factors”in our Annual Report on Form 10-K for the year ended December 31, 2017 .

Cash Flow Summary  

The table below summarizes our cash flows:

	Nine Months Ended September 30,
	2018				2017
	($ in thousands)
Cash flows from operating activities	$	48,390			$	(13,887	)
Cash flows from investing activities	$	(63,320	)		$	(25,658	)
Cash flows from financing activities	$	12,026			$	40,090
Cash and cash equivalents at beginning of period	$	5,729			$	4
Cash and cash equivalents at end of period	$	2,825			$	549

Operating cash flows  

Cash flows from operating activities have generally trended the same as our net income (loss) adjusted for non-cash items of depreciation, depletion and amortization, equity-based compensation, amortization of deferred financing costs, contract termination costs, unrealized losses on derivative instruments, and unrealized (gain) loss on fair value of warrants. Significant changes in our working capital resulted from lower account receivable balances in 2018, offset by higher prepaid expenses relating to our San Antonio plant and decrease in our current portion of long-term debt liability due to the refinance in January 2018.

Investing cash flows  

Cash flows used in investing activities increased during the nine months ended September 30, 2018 , due to construction of the San Antonio plants. We had significantly curtailed our capital expenditures to comply with our bank covenants that limited capital expenditures during the nine months ended September 30, 2017 .

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Financing cash flows  

Our cash balance as of September 30, 2018 , was $2.8 million compared to $5.7 million as of December 31, 2017 , and $0.5 million as of September 30, 2017 . During 2017, We were subject to a cash dominion requirement as per Amendment No. 11 to our Prior Credit Agreement, which required all cash receipts by us and our subsidiaries to be swept on a daily basis and used to reduce outstanding borrowings under the Credit Agreement. We maintained a minimal cash balance and managed our cash on a daily basis and made advances against the revolver based on our daily disbursements. Following our entry into our Credit Agreement on January 5, 2018, we are in compliance with the requirements for excess availability and no longer in a dominion period for purposes of the agreement.

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

	Nine Months Ended September 30,
	2018				2017
	($ in thousands)
Net debt proceeds (payments)	$	25,418			$	45,400
Payment of financing costs	(11,971		)		(3,024		)
Other	(1,421		)		(2,286		)
Total	$	12,026			$	40,090

In January 2018, we entered into the Credit Agreement and Second Lien Note Purchase Agreement described in Note 4 to our Condensed Consolidated Financial Statements. Proceeds of the sale of the notes under the Second Lien Note Purchase Agreement were used (i) to fully pay off the $40 million Partnership’s existing second lien term credit facility, (ii) to fully pay off the obligations under the Partnership’s existing revolving credit facility, (iii) to finance capital expenditures, (iv) to pay fees and expenses incurred in connection with the new second lien facility and (v) for general business purposes.

In April 2017, we entered into a second lien term loan for $40 million in connection with our acquisition in San Antonio. Proceeds of the new term credit facility were used to (i) pay down a portion of the our existing revolving credit facility, (ii) fund the acquisition described in Note 2 (iii) pay fees and expenses incurred in connection with the new term credit facility and (iv) for general business purposes.

ADJUSTED EBITDA  

We calculate Adjusted EBITDA, a non-GAAP measure, in accordance with our current Credit Agreement as: net income (loss) plus consolidated interest expense (net of interest income), income tax expense, depreciation, depletion and amortization expense, non-cash charges and losses that are unusual or non-recurring less income tax benefits and gains that are unusual or non-recurring and other adjustments allowable under our current Credit Agreement.   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: 

•	our debt covenant compliance. Adjusted EBITDA is a key component of critical covenants to our Credit Agreement;

•	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. 

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.  

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Reconciliation of Net Income (Loss) and Operating Cash Flows to Adjusted EBITDA  

The following table reconciles net income (loss) to Adjusted EBITDA for the three months ended September 30, 2018 , and 2017 :

	Continuing								Discontinued								Consolidated
	Three Months Ended September 30,
	2018				2017				2018				2017				2018				2017
	($ in thousands)
Net income (loss)	$	(3,853	)		$	5,482			$	—			$	(468	)		$	(3,853	)		$	5,014
Interest expense, net	6,907				5,073				—				—				6,907				5,073
Depreciation, depletion and amortization	5,316				6,078				—				—				5,316				6,078
Provision (benefit) for income taxes	33				(58		)		—				—				33				(58		)
EBITDA	8,403				16,575				—				(468		)		8,403				16,107
Equity-based compensation expense	364				343				—				—				364				343
Reduction in escrow receivable	—				—				—				468				—				468
Provision for doubtful accounts	287				—				—				—				287				—
Accretion expense	30				25				—				—				30				25
Retirement of assets	123				—				—				—				123				—
Other state and local taxes	395				477				—				—				395				477
Non-cash deferred lease expense	(208		)		2,223				—				—				(208		)		2,223
Unrealized loss (gain) on fair value of warrant	(1,467		)		(900		)		—				—				(1,467		)		(900		)
Adjusted EBITDA	$	7,927			$	18,743			$	—			$	—			$	7,927			$	18,743

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The following table present a reconciliation of net income (loss) to Adjusted EBITDA for the nine months ended September 30, 2018 ,  and  2017 :

	Continuing								Discontinued								Consolidated
	Nine Months Ended September 30,
	2018				2017				2018				2017				2018				2017
	($ in thousands)
Net income (loss)	$	7,061			$	(9,333	)		$	—			$	(3,125	)		$	7,061			$	(12,458	)
Interest expense, net	24,135				13,353				—				—				24,135				13,353
Depreciation, depletion and amortization	15,532				16,409				—				—				15,532				16,409
Provision (benefit) for income taxes	183				(58		)		—				—				183				(58		)
EBITDA	46,911				20,371				—				(3,125		)		46,911				17,246
Equity-based compensation expense	1,224				1,020				—				—				1,224				1,020
Contract and project terminations	1,689				—				—				—				1,689				—
Reduction in escrow receivable	—				—				—				3,125				—				3,125
Provision for doubtful accounts	310				—				—				—				310				—
Accretion expense	92				83				—				—				92				83
Retirement of assets	443				60				—				—				443				60
Other state and local taxes	1,185				1,357				—				—				1,185				1,357
Non-cash deferred lease expense	(2,429		)		6,453				—				—				(2,429		)		6,453
Unrealized (gain) loss on fair value of warrant	(1,899		)		(3,212		)		—				—				(1,899		)		(3,212		)
Other adjustments allowable under our Credit Agreement	1,149				213				—				—				1,149				213
Adjusted EBITDA	$	48,675			$	26,345			$	—			$	—			$	48,675			$	26,345

The following table reconciles Adjusted EBITDA to our operating cash flows for the three and nine months ended September 30, 2018 , and 2017 :

	Three Months Ended September 30,								Nine Months Ended September 30,
	2018				2017				2018				2017
	($ in thousands)
Adjusted EBITDA	$	7,927			$	18,743			$	48,675			$	26,345
Interest expense, net	(5,852		)		(4,169		)		(17,538		)		(10,828		)
Income tax expense	(429		)		(419		)		(1,369		)		(1,299		)
Other adjustments allowable under our Credit Agreement	—				—				(1,149		)		(213		)
Cost to retire assets	(19		)		—				(19		)		19
Non-cash deferred lease expense	208				(2,223		)		2,429				(6,453		)
Change in other operating assets and liabilities	10,453				(18,646		)		17,361				(21,458		)
Cash flows from operating activities:	$	12,288			$	(6,714	)		$	48,390			$	(13,887	)
Cash flows from investing activities:	$	(7,544	)		$	(2,036	)		$	(63,320	)		$	(25,658	)
Cash flows from financing activities:	$	(3,035	)		$	9,110			$	12,026			$	40,090

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ITEM 3.                                                 QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK  

Information about market risks for the nine months ended September 30, 2018 , does not differ materially from that discussed under Item 7A of our Annual Report on Form 10-K for the year ended December 31, 2017 .  

ITEM 4.                                                  CONTROLS AND PROCEDURES  

Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of September 30, 2018 . Based on such evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of such date, our disclosure controls and procedures were effective.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting identified in management’s evaluation required by Rule 13a-15(d) and 15d-15(d) of the Exchange Act during the quarter ended September 30, 2018 , that materially affected, or that are reasonably likely to materially affect, our internal control over financial reporting.

PART II                                       OTHER INFORMATION  

ITEM 1.                                       LEGAL PROCEEDINGS  

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

Environmental Matters

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

In January 2016, AEC experienced a leak in its proprietary fuel pipeline that connects the bulk storage terminal to the transmix facility located in Birmingham, Alabama. AEC management notified the controlling governmental agencies of this condition, and commenced efforts to locate the leak, determine the cause of the leak, repair the leak, and remediate known contamination to the proximate soils and sub-grade. These efforts remain in progress, and management does not expect the costs to repair and remediate these conditions to have a material impact on our financial position, results of operations, or cash flows.

Under the Restated Purchase Agreement, we agreed to indemnify Sunoco against these and any other environmental liabilities associated with the business and operations of the Fuel business prior to its sale, subject to certain exceptions. We have obtained an environmental insurance policy which, pursuant to the terms of the Restated Purchase Agreement, acts as the first recourse coverage for any pre-closing environmental liability asserted by Sunoco with our indemnification obligation being for any claims in excess of the insurance policy coverage or in the event a claim is denied under the insurance policy. Our management does not expect our environmental indemnification obligations pursuant to the Restated Purchase Agreement will have a material adverse effect on our future results of operations, financial position or cash flow.

ITEM 1A.                                                 RISK FACTORS  

In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2017 , which could materially affect our business, financial condition or future results.  The risks described in this report and in our Annual Report on Form 10-K are not

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the only risks we face.  Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results.  

ITEM 4.                                       MINE SAFETY DISCLOSURES  

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

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

ITEM 5.                                                  OTHER INFORMATION 

On June 4, 2018, our subsidiary, Superior Silica Sands LLC, received an imminent danger order (the Order) under section 107(a) of the Federal Mine Safety and Health Act of 1977 at our San Antonio plant. The order stated that a customer truck driver was on top of the loaded trailer without wearing fall protection. No injuries occurred from this incident. We took corrective action with respect to this incident. This Order should have been reported on a Current Report on Form 8-K, under Item 1.04 (Mine Safety - Reporting of Shutdowns and Patterns of Violations).

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ITEM 6.                                       EXHIBITS  

Exhibit Number		Description
3.1		Certificate of Limited Partnership of Emerge Energy Services LP (incorporated by reference to Exhibit 3.1 to the Registrant’s Registration Statement on Form S-1, Registration No. 333-187487).
3.2		Amendment to Certificate of Limited Partnership of Emerge Energy Services LP (incorporated by reference to Exhibit 3.2 to the Registrant’s Registration Statement on Form S-1, Registration No. 333-187487).
3.3		First Amended and Restated Limited Partnership Agreement of Emerge Energy Services LP, dated as of May 14, 2013 (incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K, filed with the SEC on May 20, 2013).
3.4		Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership of Emerge Energy Services LP, dated as of August 15, 2016 (incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K, filed with the SEC on August 16, 2016).
3.5		Certificate of Formation of Emerge Energy Services GP LLC (incorporated by reference to Exhibit 3.5 to the Registrant’s Registration Statement on Form S-1, Registration No. 333-187487) .
3.6		Amendment to Certificate of Formation of Emerge Energy Services GP LLC (incorporated by reference to Exhibit 3.6 to the Registrant’s Registration Statement on Form S-1, Registration No. 333-187487).
3.7		Amended and Restated Limited Liability Company Agreement of Emerge Energy Services GP, LLC, dated as of May 14, 2013 (incorporated by reference to Exhibit 3.2 to the Registrant’s Current Report on Form 8-K, filed with the SEC on May 20, 2013).
4.1		Registration Rights Agreement, dated January 5, 2018, by and between Emerge Energy Services LP, Mezzanine Partners III, L.P., AP Mezzanine Partners III, L.P., EES Offshore, LLC and OC II AIV II LP (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K, filed with the SEC on January 8, 2018).
10.1		Second Amended and Restated Revolving Credit and Security Agreement, dated as of January 5, 2018, among Emerge Energy Services LP, as parent guarantor, the Borrowers party thereto, PNC Bank, National Association, as administrative agent and collateral agent, and the Lenders party thereto (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K, filed with the SEC on January 8, 2018).
10.2		Second Lien Note Purchase Agreement, dated as of January 5, 2018, between Emerge Energy Services LP, Emerge Energy Services Operating LLC, as issuers, and HPS Investment Partners, LLC as notes agent and collateral agent (incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K, filed with the SEC on January 8, 2018).
31.1*		Certification of Chief Executive Officer under Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*		Certification of Chief Financial Officer under Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*		Certification of Chief Executive Officer under Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*		Certification of Chief Financial Officer under Section 906 of the Sarbanes-Oxley Act of 2002.
95.1*		Mine Safety Disclosure Exhibit.
101*		Interactive Data Files - XBRL.

*    Filed herewith (or furnished in the case of Exhibits 32.1 and 32.2).

†    Certain portions have been omitted pursuant to a confidential treatment request. Omitted information has been separately filed with the Securities and Exchange Commission.

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SIGNATURES

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

Date: November 7, 2018  

	EMERGE ENERGY SERVICES LP
	By:	EMERGE ENERGY SERVICES GP LLC, its general partner
	By:	/s/ Rick Shearer
		Rick Shearer
		President and Chief Executive Officer
		(Principal Executive Officer)
	By:	/s/ Deborah Deibert
		Deborah Deibert
		Chief Financial Officer
		(Principal Financial Officer)

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