UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the quarterly period ended ~~June 30, 2017~~March 31, 2018

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

For the transition period from to

Commission File No. 001-35912

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.)

~~6000 Western Place,~~5600 Clearfork Main Street, Suite ~~465,~~400, Fort Worth, Texas ~~76107~~76109		(817) 618-4020
(Address of principal executive offices)		(Registrant’s telephone number, including area code)

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



Title of Each Class		Name of Each Exchange On Which Registered
Common Units Representing Limited Partner Interests		New York Stock Exchange

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

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

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

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



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

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o Yes o No

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

As of ~~July 28, 2017, 30,150,782~~April 25, 2018, 31,006,173 common units were outstanding.

TABLE OF CONTENTS



		Page
	PART I – FINANCIAL INFORMATION

	Forward-Looking Statements	3

Item 1.	Financial Statements	4

	Unaudited Condensed Consolidated Balance Sheets as of ~~June 30, 2017~~March 31, 2018 and December 31, ~~2016~~2017	4

	Unaudited Condensed Consolidated Statements of Operations for the Three ~~and Six~~ Months Ended ~~June 30,~~March 31, 2018 and 2017 ~~and 2016~~	5

	Unaudited Condensed Consolidated Statement of Preferred Units and Partners’ Equity for the ~~Six~~Three Months Ended ~~June 30, 2017~~March 31, 2018	6

	Unaudited Condensed Consolidated Statements of Cash Flows for the ~~Six~~Three Months Ended ~~June 30,~~March 31, 2018 and 2017 ~~and 2016~~	7

	Notes to Unaudited Condensed Consolidated Financial Statements	8

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	2120

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	3228

Item 4.	Controls and Procedures	3228

	PART II – OTHER INFORMATION

Item 1.	Legal Proceedings	3229

Item 1A.	Risk Factors	3329

Item 4.	Mine Safety Disclosures	3329

Item 6.	Exhibits	3430

FORWARD-LOOKING STATEMENTS

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

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, ~~2016.~~2017.

When considering forward-looking statements, you should keep in mind the known material risk factors and other cautionary statements set forth in our Annual Report on Form 10-K for the year ended December 31, ~~2016~~2017 in “Risk Factors” and in this Form 10-Q in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Risk Factors.” Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise.

PART I FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

EMERGE ENERGY SERVICES LP

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

($ in thousands, except unit data)


	June 30, 2017		December 31, 2016		March 31, 2018		December 31, 2017
ASSETS
Current assets:
Cash and cash equivalents	$	189	$	4	$	8,689	$	5,729
Trade and other receivables, net	42,539		25,103		66,768		56,951
Inventories	21,273		17,457		14,889		27,825
Prepaid expenses and other current assets	6,970		11,374		8,173		6,331
Total current assets	70,971		53,938		98,519		96,836

Property, plant and equipment, net	181,445		165,484		203,813		185,970
Intangible assets, net	3,223		4,781		570		1,664
Other assets, net	25,209		25,330		22,563		24,422
Non-current assets held for sale	202		371
Total assets	$	281,050	$	249,904	$	325,465	$	308,892

LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable	$	25,599	$	11,221	$	21,976	$	18,819
Accrued liabilities	13,976		11,629		16,012		29,718
Current portion of long-term debt					8,063		—
Total current liabilities	39,575		22,850		46,051		48,537

Long-term debt, net of current portion	168,690		134,012		195,690		176,351
Business acquisition obligation, net of current portion	6,303		8,063		4,553		5,013
Other long-term liabilities	28,680		30,323		22,228		29,882
Total liabilities	243,248		195,248		268,522		259,783

Commitments and contingencies
Preferred units - Series A - Par value of $1,000: 0 units and 10,000 units issued and outstanding as of June 30, 2017 and December 31, 2016, respectively	—		6,914
Partners’ equity:
General partner	—		—		—		—
Limited partner common units - 30,147,725 units and 29,076,456 units issued and outstanding as of June 30, 2017 and December 31, 2016, respectively	37,802		47,742
Limited partner common units - 31,006,173 units and 30,174,940 units issued and outstanding as of March 31, 2018 and December 31, 2017, respectively					56,943		49,109
Total partners’ equity	37,802		47,742		56,943		49,109
Total liabilities and partners’ equity	$	281,050	$	249,904	$	325,465	$	308,892

See accompanying notes to unaudited condensed consolidated financial statements.

EMERGE ENERGY SERVICES LP

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

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


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended March 31,
	2017			2016			2017			2016			2018			2017
Revenues	$	82,602		$	24,825		$	157,946		$	54,495		$	106,750		$	75,344
Operating expenses:
Cost of goods sold (excluding depreciation, depletion and amortization)	71,428			38,354			143,739			82,144			80,242			72,311
Depreciation, depletion and amortization	5,675			4,870			10,331			9,777			4,861			4,656
Selling, general and administrative expenses	6,850			4,459			12,728			11,234			8,571			5,878
Contract and project terminations	—			10			—			4,036			1,689			—
Total operating expenses	83,953			47,693			166,798			107,191			95,363			82,845
Operating income (loss)	(1,351		)	(22,868		)	(8,852		)	(52,696		)	11,387			(7,501		)
Other expense (income):
Interest expense, net	5,082			5,283			8,280			9,877			10,492			3,198
Other	(3,008		)	(2		)	(2,317		)	(3		)	(688		)	691
Total other expense	2,074			5,281			5,963			9,874			9,804			3,889
Income (loss) from continuing operations before provision for income taxes	(3,425		)	(28,149		)	(14,815		)	(62,570		)	1,583			(11,390		)
Provision (benefit) for income taxes	—			1			—			21			97			—
Net income (loss) from continuing operations	(3,425		)	(28,150		)	(14,815		)	(62,591		)
Income (loss) from discontinued operations, net of taxes	(2,657		)	5,253			(2,657		)	5,479
Net income (loss)	$	(6,082	)	$	(22,897	)	$	(17,472	)	$	(57,112	)	$	1,486		$	(11,390	)

Basic and diluted earnings (loss) per unit (1):
Earnings (loss) per common unit from continuing operations	$	(0.11	)	$	(1.17	)	$	(0.49	)	$	(2.59	)
Earnings (loss) per common unit from discontinued operations	(0.09		)	0.22			(0.09		)	0.23
Basic and diluted earnings (loss) per common unit	$	(0.20	)	$	(0.95	)	$	(0.58	)	$	(2.36	)
Earnings (loss) per common unit (1)
Basic earnings (loss) per common unit													$	0.05		$	(0.38	)
Diluted earnings (loss) per common unit													$	0.05		$	(0.38	)

Weighted average number of common units outstanding - basic and diluted (1)	30,147,725			24,129,418			30,104,613			24,125,320

(1) See Note 9.
Weighted average number of common units outstanding - basic													31,212,968			30,061,022
Weighted average number of common units outstanding - diluted													31,371,382			30,061,022
(1) See Note 8.

See accompanying notes to unaudited condensed consolidated financial statements.

EMERGE ENERGY SERVICES LP

UNAUDITED CONDENSED CONSOLIDATED STATEMENT OF PREFERRED UNITS AND PARTNERS’ EQUITY

($ in thousands)

Limited Partner Common Units General Partner
(non-economic
interest) Total Partners’ Equity Preferred Units

Balance at December 31, 2016 $ 47,742
$ —
$ 47,742
$ 6,914

Net loss (17,472 ) —
(17,472 ) —

Equity-based compensation 677
—
677
—

Conversion of preferred units 6,914
—
6,914
(6,914 )
Other (59 ) —
(59 ) —

Balance at June 30, 2017 $ 37,802
$ —
$ 37,802
$ —



	Limited Partner Common Units			General Partner (non-economic interest)		Total Partners’ Equity

Balance at December 31, 2017	$	49,109		$	—	$	49,109
Net income	1,486			—		1,486
Equity-based compensation	434			—		434
Issuance of equity	5,974			—		5,974
Other	(60		)	—		(60		)
Balance at March 31, 2018	$	56,943		$	—	$	56,943

See accompanying notes to unaudited condensed consolidated financial statements.

EMERGE ENERGY SERVICES LP

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

($ in thousands)


	Six Months Ended June 30,						Three Months Ended March 31,
	2017			2016			2018			2017
Cash flows from operating activities:
Net income (loss)	$	(17,472	)	$	(57,112	)	$	1,486		$	(11,390	)
Adjustments to reconcile net income (loss) to net cash flows from operating activities:
Depreciation, depletion and amortization	10,331			12,131			4,861			4,656
Equity-based compensation expense	677			136			434			347
Project and contract termination costs - non-cash portion	—			4,011
Unrealized gain on fair value of warrant	(2,312		)	—
Write-down of escrow receivable	2,657			—
Project and contract termination costs							1,689			—
Unrealized (gain) loss on fair value of warrant							(677		)	696
Provision for doubtful accounts	—			1,746			3			—
Loss (gain) on disposal of assets	79			76			2			(6		)
Amortization of debt discount/premium and deferred financing costs	1,835			1,506			4,528			663
Write-down of inventory	—			5,394
Unrealized (gain) loss on derivative instruments	(214		)	665			—			(149		)
Other non-cash	58			59
Other non-cash charges							30			29
Changes in operating assets and liabilities:
Accounts receivable	(17,437		)	6,845			(9,815		)	(15,609		)
Inventories	(3,816		)	8,135			12,936			4,204
Prepaid expenses and other current assets	1,748			1,643			(1,843		)	(784		)
Accounts payable and accrued liabilities	16,573			1,560			(3,155		)	4,194
Other assets	120			173			265			210
Cash flows from operating activities:	(7,173		)	(13,032		)
Cash flows from operating activities							10,744			(12,939		)

Cash flows from investing activities:
Purchases of property, plant and equipment	(3,403		)	(11,010		)	(30,102		)	(1,399		)
Net proceeds from disposal of assets	211			(9		)	9			7
Asset acquisition	(20,430		)	—
Collection of notes receivable	—			7
Cash flows from investing activities:	(23,622		)	(11,012		)
Cash flows from investing activities							(30,093		)	(1,392		)

Cash flows from financing activities:
Proceeds from line of credit borrowings	154,820			141,345			9,510			76,100
Proceeds from second lien term loan	39,597			—			175,000			—
Repayment of line of credit borrowings	(158,593		)	(130,451		)	(143,700		)	(57,929		)
Repayment of other long-term debt							(5,882		)	—
Payment of business acquisition obligation	(1,799		)	(382		)	(595		)	(1,519		)
Payment of financing costs	(2,982		)	(4,177		)	(11,964		)	(163		)
Other financing activities	(63		)	(3		)	(60		)	(63		)
Cash flows from financing activities:	30,980			6,332
Cash flows from financing activities							22,309			16,426

Cash and cash equivalents:
Net increase (decrease)	185			(17,712		)	2,960			2,095
Balance at beginning of period	4			20,870			5,729			4
Balance at end of period	$	189		$	3,158		$	8,689		$	2,099

See accompanying notes to unaudited condensed consolidated financial statements.

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 ~~a growth-oriented energy services company~~ engaged in the business of mining, ~~producing,~~processing, and distributing silica sand, ~~that is~~ 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.

~~The Fuel~~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.

On August 31, 2016, we completed the sale of our Fuel business pursuant to an Amended and Restated Purchase and Sale Agreement, dated August 31, 2016 (the “Restated Purchase Agreement”), with Susser Petroleum Operating Company LLC and Sunoco LP (together, “Sunoco”). Sunoco paid Emerge a purchase price of $167.7 million in cash (subject to certain working capital and other adjustments in accordance with the terms of the Restated Purchase Agreement), of which $14.25 million was placed into several escrow accounts to satisfy potential claims from Sunoco for indemnification under the Restated Purchase Agreement. During the second quarter of 2017, we received the entire $2.25 million of the Renewable Fuel Standard escrow. Additionally, we wrote off $2.7 million of the hydrotreator and pipeline escrow receivables relating to completion delays and cost overruns. Any escrowed funds remaining after certain periods of time set forth in the Restated Purchase Agreement will be released to Emerge, provided that no unsatisfied indemnity claims exist at such time.

The results of operations of the Fuel business have been classified as discontinued operations for all periods presented. We now operate our continuing business in a single sand segment. We report silica sand operations as our continuing operations and fuel operations as our discontinued operations.

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 ~~2016~~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.

~~Reclassifications~~

Certain reclassifications have been made to prior period amounts to conform to the current period presentation. These reclassifications do not impact net income and do not reflect a material change in the information previously presented in our Condensed Consolidated Statements of Operations.

2. ASSET ACQUISITION

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. ~~(collectively “Osburn Materials”)~~ for $20 million. The transaction was funded with a ~~new~~ $40 million term loan. ~~Osburn Materials~~The San Antonio site is located ~~approximately~~ 25 miles south of San Antonio, Texas, and ~~produces~~previously produced and ~~sells sand~~sold construction, foundry and ~~construction materials~~sports sands, but did not serve the energy markets. We upgraded the existing operations for conversion into frac sand ~~sales~~production and commenced frac sand ~~productin~~production in July 2017. ~~Osburn Materials’ current sand~~Our San Antonio site’s reserves ~~which consists~~consist mostly of 40/70 and 100 mesh ~~fine~~ sands ~~meets~~and meet American Petroleum Institute (“API”) specifications for all grades.

We early adopted the provisions of ~~ASC~~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, ~~we believe that~~ 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 acquisition to the assets acquired on a relative fair value basis at the acquisition date. The ~~preliminary~~ 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. ~~Additionally, we are finalizing the sand reserves estimates.~~ 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. Based on our evaluation, 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 the type and location of our customers. The term between invoicing and the payment due date is 30 days in most cases. For certain customers, we require payment before the product is delivered.

The ~~assets acquired~~following table presents our revenues disaggregated by nature of product:



	Three Months Ended
	March 31, 2018			March 31, 2017
	$ in thousands		Tons in thousands	$ in thousands		Tons in thousands

Frac sand revenues	$	105,971	1,437	$	75,182	1,245
Non-frac sand revenues	779		66	162		6
Total revenues	$	106,750	1,503	$	75,344	1,251

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 ~~been included~~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 ~~consolidated balance sheets as of June 30, 2017~~ability to recognize the variability in consideration related to this condition. Demurrage fees are assessed to customers for not returning the railcar timely and ~~will be depreciated and depleted~~ according to the ~~policies described in~~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 ~~Annual Report~~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 ~~Form 10-K for the year ended December 31, 2016.~~our consolidated financial statements is immaterial.

3. ~~DISCONTINUED OPERATIONS~~

~~At March 31, 2016, the assets~~After a thorough and ~~liabilities~~extensive analysis of all of our ~~Fuel business were classified as held for sale~~long-term, minimum purchase supply agreements and a review of the ~~results~~standard terms of ~~operations have been classified as discontinued operations for all periods presented~~the purchase orders, we determined that there is no material change in ~~accordance with ASU 2014-08,~~ ~~Reporting Discontinued Operations~~the transaction price and ~~Disclosures of Disposals of Components of an Entity.~~

~~The following corporate costs were~~amounts allocated to ~~discontinued operations~~performance obligations, or the timing of satisfaction of performance obligations under ASC 606 compared to our accounting for ~~all periods presented:~~these items in previous periods.

~~Interest on the revolver was allocated to the discontinued operations based on the allocation of debt between Sand and Fuel business.~~

~~Equity-based compensation costs recognized for the Fuel business employees were allocated to discontinued operations.~~

~~The taxes paid on behalf of the Fuel business were compiled by review of prior tax filings and payments. These amounts were allocated to discontinued operations.~~

~~General corporate overhead costs were not allocated to discontinued operations.~~

~~Summarized results of the discontinued operations for the three and six months ended June 30, 2017 and 2016 are as follows :~~

Three Months Ended June 30, Six Months Ended June 30,

2017 2016 2017 2016

($ in thousands)
Revenues (1) $ —
$ 101,982
$ —
$ 182,463

Cost of goods sold (excluding depreciation, depletion and amortization) (1) —
93,844
—
169,544

Depreciation and amortization —
—
—
2,354

Selling, general and administrative expenses —
2,194
—
3,792

Interest expense, net —
686
—
1,283

Other expenses 2,657
—
2,657
—

Income from discontinued operations before provision for income taxes (2,657 ) 5,258
(2,657 ) 5,490

Provision for income taxes —
5
—
11

Income from discontinued operations, net of taxes $ (2,657 ) $ 5,253
$ (2,657 ) $ 5,479

(1) Fuel revenues and cost of goods sold include excise taxes and similar taxes: $ —
$ 13,405
$ —
$ 26,488

Discontinued Operations

On August 31, 2016, we completed the sale of our Fuel business pursuant to the terms of the ~~Restated~~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:

~~Table of contents~~

$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 ~~June~~ 2017, we wrote off ~~a $2.5 million of this~~the entire receivable relating to hydrotreator completion delays and cost overruns. This non-cash charge is included in Other expenses in our results of discontinued operations. Any unutilized escrow balance, along with any accrued interest thereon, will be paid 60 days after the substantial completion of the Birmingham hydrotreater.

$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. ~~As of June 30, 2017, we estimated our receivable at $850,000. This non-cash charge is included in Other expenses in our results of discontinued operations~~ 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.

~~The following table represents the gain on sale from the Fuel business recognized in the third quarter of 2016 (in thousands).~~

Purchase price $ 167,736

Adjustments:
Working capital true-up 3,398

Other adjustments (2,911 )
General escrow (7,000 )
Hydrotreater escrow (4,000 )
Other escrow (3,250 )
Net proceeds 153,973

Less:
Net book value of assets and liabilities sold (125,317 )
Escrow receivable 10,597

Transaction costs including commissions (7,679 )
Other receivables 125

Gain on sale of Fuel business $ 31,699

4.~~OTHER FINANCIAL DATA~~

Private Placement

~~On August 8, 2016, we entered into the Purchase Agreement~~In connection with ~~the Purchaser to issue and sell to the Purchaser in a~~our private placement ~~an aggregate principal amount of $20 million of our Series A Preferred Units and a Warrant that may be exercised to purchase common units representing limited partner interests~~ in ~~the Partnership.~~

~~The first half of the Preferred Units converted into 993,049 common units on November 3,~~August 2016, ~~and the second half converted to 985,222 common units on February 15, 2017.~~

~~We also~~we issued to the ~~Purchaser~~purchaser a warrant to purchase approximately 890,000 common units at an exercise price of $10.82 per common unit. The ~~Warrant,~~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 ~~June 30, 2017.~~March 31, 2018.

~~Public Offering~~

In November 2016, we completed a public offering of 3,400,000 of our common units at a price of $10.00 per unit and granted the underwriters an option to purchase up to an additional 510,000 common units, which the underwriter exercised in full. The offering closed on November 23, 2016. We received proceeds (net of underwriting discounts and offering expenses) from the offering of approximately $36.9 million. The net proceeds from this offering were used to repay outstanding borrowings under our revolving Credit Agreement.

Allowance for Doubtful Accounts

~~We had no allowance for doubtful accounts at June 30, 2017.~~ The allowance for doubtful accounts totaled ~~$3.1 million~~$17.0 thousand at March 31, 2018, and December 31, ~~2016.~~2017.

Inventories

Inventories consisted of the following:


	June 30, 2017		December 31, 2016		March 31, 2018		December 31, 2017

	($ in thousands)				($ in thousands)
Sand finished goods	$	11,777	$	9,631	$	9,959	$	12,914
Sand work in process	9,220		7,597		4,751		14,650
Sand raw materials and supplies	276		229		179		261
Total	$	21,273	$	17,457	$	14,889	$	27,825

During the first quarter of 2016, we wrote down $5.4 million of our sand inventory based on our lower of cost or market analysis. We attributed this write-down to declining market conditions and a significant decline in prices.

Prepaid expenses and other current assets

Prepaid expenses and other current assets consisted of the following:


	June 30, 2017		December 31, 2016		March 31, 2018		December 31, 2017

	($ in thousands)				($ in thousands)
Prepaid lease assets, current	$	2,577	$	3,408
Prepaid mining costs					$	3,381	$	1,011
Prepaid lease assets, current (1)					2,415		2,496
Prepaid insurance	968		826		772		875
Escrow receivable, current	468		5,253
Prepaid transload services					693		1,274
Other	2,957		1,887		912		675
Total	$	6,970	$	11,374	$	8,173	$	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:


	June 30, 2017		December 31, 2016		March 31, 2018		December 31, 2017

	($ in thousands)				($ in thousands)
Machinery and equipment (1)	$	92,849	$	90,035	$	92,925	$	92,353
Buildings and improvements (1)	66,190		66,190		66,545		66,444
Mineral reserves					49,091		49,091
Land and improvements (1)	45,567		45,065		47,597		45,567
Mineral reserves	49,091		30,181
Construction in progress	4,272		1,878		34,870		15,696
Capitalized reclamation costs	2,521		2,445		2,521		2,521
Total cost	260,490		235,794		293,549		271,672
Accumulated depreciation and depletion	79,045		70,310		89,736		85,702
Net property, plant and equipment	$	181,445	$	165,484	$	203,813	$	185,970

(1) Includes assets under capital lease.

We classified ~~$202,000~~$393,000 and ~~$371,000 to~~$292,000 as assets held for sale as of ~~June 30, 2017~~March 31, 2018, and December 31, ~~2016.~~2017.

We recognized ~~$8.8~~$4.1 million and ~~$9.1~~$3.9 million of depreciation and depletion expense for the ~~six~~three months ended ~~June 30,~~March 31, 2018, and 2017, ~~and 2016,~~ respectively. ~~Depreciation and depletion expense for continuing operations totaled $8.3 million for the six months ended June 30, 2016.~~

Intangible Assets

Our intangible assets consisted of the following:


	Cost		Accumulated Amortization		Net		Cost		Accumulated Amortization		Net

	($ in thousands)						($ in thousands)
June 30, 2017:
March 31, 2018:
Patents							$	7,443	$	6,936	$	507
Non-compete agreement							100		37		63
Total							$	7,543	$	6,973	$	570

December 31, 2017:
Patents	$	7,443	$	4,691	$	2,752	$	7,443	$	6,188	$	1,255
Supply and transportation agreements	569		169		400		569		226		343
Non-compete agreement	100		29		71		100		34		66
Total	$	8,112	$	4,889	$	3,223	$	8,112	$	6,448	$	1,664

December 31, 2016:
Patents	$	7,443	$	3,195	$	4,248
Supply and transportation agreements	569		112		457
Non-compete agreement	100		24		76
Total	$	8,112	$	3,331	$	4,781

We recognized ~~$1.6 million and $3.0~~$0.8 million of amortization expense for each of the ~~six~~three months ended ~~June 30, 2017~~March 31, 2018 and ~~2016, respectively.~~2017. ~~Amortization expense for continuing operations totaled $1.5 million for the six months ended June 30, 2016.~~

Other Assets, Net

Other assets, net consisted of the following:


	June 30, 2017		December 31, 2016		March 31, 2018		December 31, 2017

	($ in thousands)				($ in thousands)
Deferred lease asset (1)	$	8,801	$	8,826	$	8,763	$	8,775
Prepaid lease assets, net of current portion (2)	8,450		8,616		6,575		7,153
Escrow receivable, non-current (3)	5,510		5,459		5,772		5,684
Other	2,448		2,429		1,453		2,810
Total	$	25,209	$	25,330	$	22,563	$	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. ~~See Note 3 - Discontinued Operations.~~

Accrued Liabilities

Accrued liabilities consisted of the following:


	June 30, 2017		December 31, 2016		March 31, 2018		December 31, 2017

	($ in thousands)				($ in thousands)
Logistics					$	2,816	$	5,898
Fuel sale related liabilities					2,478		2,475
Current portion of business acquisition obligations					1,790		1,952
Mining					1,544		170
Salaries and other employee-related					1,209		4,633
Sales, excise, property and income taxes					871		1,953
Deferred compensation					848		848
Sand purchases and royalties	$	3,430	$	517	768		311
Fuel sale related-liabilities	2,474		2,784
Salaries and other employee-related	2,250		710
Current portion of business acquisition obligations	1,666		1,703
Deferred compensation	848		848
Sales, excise, property and income taxes	730		136
Accrued interest	430		641		578		2,552
Construction					434		7,122
Professional fees					200		373
Current portion of contract termination	210		160		85		210
Logistics	204		1,814
Other	1,734		2,316		2,391		1,221
Total	$	13,976	$	11,629	$	16,012	$	29,718

Other Long-term Liabilities

Other long-term liabilities consisted of the following:


	June 30, 2017		December 31, 2016		March 31, 2018		December 31, 2017

	($ in thousands)				($ in thousands)
Deferred lease obligation (1)					$	11,033	$	9,561
Long-term promissory note	$	8,914	$	8,480	5,370		9,370
Deferred lease obligation (1)	6,992		5,858
Asset retirement obligation					2,814		2,792
Warrants					2,134		2,811
Contract and project terminations	5,305		5,319		877		5,348
Stock warrants	4,707		7,019
Asset retirement obligation	2,762		2,647
Other	—		1,000
Total	$	28,680	$	30,323	$	22,228	$	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 rail cars and reduced cash payments on a substantial portion of the existing rail cars in our fleets. In exchange offor these concessions, we issued at par an ~~Unsecured Promissory Note~~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. ~~The PIK~~We began paying interest in cash as of January 1, 2018. This Note will mature on June 2, 2020. We paid $1.5 million of the principal balance during the three months ended March 31, 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 offor 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 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 three months ended March 31, 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 rail cars and reduced cash payments on a substantial portion of the existing rail cars 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~~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 ~~bears~~bore interest at a rate of five percent per ~~annum~~annum. We fully extinguished this liability and ~~is due and payable within 30 days following the date on which financial statements are publicly available covering the first date on which these financial metrics have been met.~~

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)			($ in thousands)
Balance at December 31, 2016	$	5,479
Balance at December 31, 2017				$	5,557
Adjustments				(221		)
Accretion	121			8
Payments	(85		)	(4,382		)
Balance at June 30, 2017	$	5,515
Balance at March 31, 2018				$	962

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 inon 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. The original capitalized lease asset and corresponding capital lease obligation totaled $3.3 million. As of June 30, 2017, we do not have any liability for~~ 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 June 2, 2016, we issued warrants to lessors to purchase 370,000 common units representing limited partnership interests in the partnership for concessions on various long-term leases. These warrants may be exercised at any time and from time to time during next five years, at an exercise price per common unit equal to $4.77. These fair value of these warrants was calculated at $2.45 per unit based on a Black Scholes valuation model, utilizing Level 2 inputs based on the hierarchy established in ASC 820, ~~Fair Value Measurement.~~

On August 8, 2016, we, as part of the private placement described above, also issued a warrant to the ~~Purchaser~~purchaser to purchase approximately 890,000 common units at an exercise price of $10.82 per common unit. This ~~Warrant~~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 ~~$4.7~~$2.1 million and ~~$7.0~~$2.8 million at ~~June 30, 2017~~March 31, 2018, and December 31, ~~2016, respectively, and we~~2017, respectively. We recorded a a non-cash mark-to-market gain of ~~$3.0 million and $2.3~~$0.7 million during the three ~~and six~~ months ended ~~June 30, 2017, respectively.~~March 31, 2018, and a loss of $0.7 million during the three months ended March 31, 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 ~~for continuing operations~~ totaled ~~$105,045~~$297,000 and ~~$177,000~~$0 for the ~~six~~three months ended ~~June 30,~~March 31, 2018, and 2017, ~~and 2016,~~ respectively. ~~Employer contributions for discontinued operations was $118,000 for the six months ended June 30, 2016.~~

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 ~~June 30, 2017~~March 31, 2018, and December 31, ~~2016~~2017, from such significant customers are set forth below:


	June 30, 2017		December 31, 2016		March 31, 2018		December 31, 2017
Customer A	16	%	16	%	25	%	17	%
Customer B	14	%	22	%	19	%	20	%
Customer C	14	%	*		*		13	%
Customer D	12	%	13	%

An asterisk indicates trade receivables ~~are~~ less than ten percent.

Significant customers

The table shows the %percent of revenue of our significant customers for our continuing operations represented for the ~~six~~three months ended ~~June 30, 2017~~March 31, 2018, and ~~2016.~~2017.


	June 30, 2017		June 30, 2016		March 31, 2018		March 31, 2017
Customer A					28	%	17	%
Customer B	26	%	35	%	12	%	*
Customer D	16	%	*		10	%	32	%
Customer E	*		16	%

An asterisk indicates revenue is less than ten percent.

Geographical Data

Although we own no long-term assets outside the United States, ~~our Sand business~~we began selling ~~product~~sand in Canada during 2013. We recognized ~~$7.8~~$11.8 million and ~~$8.0~~$5.4 million of revenues in Canada for the ~~six~~three months ended ~~June 30,~~March 31, 2018, and 2017, ~~and 2016,~~ respectively. All other sales have occurred in the United States.

Recent Issued Accounting ~~Pronouncements~~Pronouncement

~~In May 2014, August 2015 and May 2016, the FASB issued ASU 2014-09,~~ ~~Revenue from Contracts with Customers, ASU 2015-14,~~ ~~Revenue from Contracts with Customers, Deferral of the Effective Date, and ASU 2016-12,~~ ~~Revenue from Contracts with Customers, Narrow-Scope Improvements and Practical Expedients~~, respectively, as a new Topic, Accounting Standards Codification Topic 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. This guidance is effective for annual periods beginning after December 15, 2017 with early adoption permitted on January 1, 2017 and shall be applied retrospectively to each period presented or as a cumulative-effect adjustment as of the date of adoption. We have certain contractual arrangements that include "take-or-pay" provisions. The fixed fees to which we have an unconditional right under these contracts could be subject to certain recognition changes and additional disclosure under ASU 2014-09. As we are in the process of evaluating the impact of the standard, we have not yet quantified the impact of adoption or determined the method of adoption. During 2017, we will perform the remainder of our implementation process, which will include quantification of impact, selection of adoption method and development of policies. We will adopt this guidance in the first quarter of 2018.

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 ~~sheet.~~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. Early adoption is permitted for all entities. We currently have significant long-term operating leases for rail cars and transload facilities. Pursuant to the adoption, we will record substantial liabilities and corresponding assets for these leases. We have engaged an independent consultant to assist us in our assessment of our lease contracts. 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.

~~In January 2017, the FASB issued ASU 2017-01,~~ ~~Business Combinations. This ASU provides guidance~~ We plan to entities to assist with evaluating when a set of transferred assets and activities (collectively, the "set") is a business and provides a screen to determine when a set is not a business. Under this ASU, when substantially all of the fair value of gross assets acquired (or disposed of) is concentrated in a single identifiable asset, or group of similar assets, the assets acquired would not represent a business. Also, to be considered a business, an acquisition would have to include an input and a substantive process that together significantly contribute to the ability to produce outputs. ASU 2017-01 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017, and should be applied on a prospective basis to any transactions occurring within the period of adoption. Early adoption is permitted for interim or annual periods in which the financial statements have not been issued. We adoptedadopt this guidance ~~in the second quarter of 2017 and applied it to our asset acquisition described in Note 2 - Asset Acquisition.~~on January 1, 2019.

5.4. LONG-TERM DEBT

Following is a summary of our long-term debt:

June 30, 2017 December 31, 2016

($ in thousands)
Revolving credit facility $ 136,928
$ 140,701

Second lien term loan 40,000
—

Less: Deferred financing costs, net (8,238 ) (6,689 )
Total long-term debt $ 168,690
$ 134,012



	March 31, 2018			December 31, 2017

	($ in thousands)
Second lien term loan - principal	$	215,000		$	40,000
Revolving credit facility - principal	9,510			143,700
Less: Deferred financing costs, net	(20,757		)	(7,349		)
Total debt	203,753			176,351
Less current portion	(8,063		)	—
Long-term debt	$	195,690		$	176,351

Revolving Credit Facility

On ~~June 27, 2014,~~January 5, 2018, we entered into ~~an amended~~a $75.0 million Second Amended and ~~restated revolving credit~~Restated Revolving Credit and ~~security agreement (as amended, the~~Security Agreement (the “Credit Agreement”), among ~~Emerge Energy Services LP,~~the Partnership, as parent guarantor, each of its subsidiaries, as borrowers, ~~(the “Borrowers”), and~~ PNC Bank, National Association (“PNC Bank”), as administrative agent and collateral agent, ~~(the “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 June 27, 2019 and, after giving effect to the amendments described below, consists of a $190 million revolving credit facility, which included a sub-limit of up to $20 million for letters of credit, and incurs interest at a rate equal to either, at our option, LIBOR plus 5.00% or the base rate plus 4.00%. We also incur a commitment fee of 0.375% on committed amounts that are neither used for borrowings nor under letters of credit.January 5, 2022. Substantially all ~~of the~~our assets ~~of the Borrowers~~ are pledged as collateral ~~under the Credit Agreement.~~

On August 31, 2016, we closed the sale of the Fuel business, used the net proceeds therefrom to repay outstanding borrowings under the Credit Agreement and entered into Amendment No. 11 to the Credit Agreement with the Borrowers, the lenders and the agent. Amendment No. 11, among other things, restated the Credit Agreement and provided a full waiver for all defaults or events of default arising out of our failure to comply with the financial covenant to generate minimum amounts of adjusted EBITDA during the quarters ended March 31, 2016, June 30, 2016 and September 30, 2016 and the covenant to maintain the minimum amount of excess availability for any date prior to September 1, 2016.

~~Pursuant to Amendment No. 11, the Credit Agreement now requires the Partnership to maintain the following financial covenants:~~

~~a covenant to maintain $15 million of excess availability (as defined in the Credit Agreement);~~

~~a covenant to limit capital expenditures (as defined in the Credit Agreement) to certain maximum amounts for each quarter through March 31, 2019;~~

~~beginning with the quarter ending June 30, 2017, a covenant to generate consolidated EBITDA (as defined in the Credit Agreement) in certain minimum amounts;~~

beginning with the quarter ending March 31, 2018, a covenant to maintain an interest coverage ratio (as defined in the Credit Agreement) of not less than 2.00 to 1.00, which is scheduled to increase to 3.00 to 1.00 for the fiscal quarter ending March 31, 2019; and

a covenant to raise at least $31.2 million of net proceeds from the issuance and sale of common equity by November 30, 2016, which was satisfied by our underwritten sale of common units which closed on November 23, 2016.

~~In addition, the Credit Agreement also prohibits us from making cash distributions to our unitholders and requires 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.~~

On April 12, 2017, the Partnership entered into Amendment No. 12 to the Credit Agreement. The Amendment amended the Revolving Credit Agreement to permit the Partnership and the Borrowers to enter into the Second Lien Term Loan Agreement and to reduce commitments under thefirst lien basis. This revolving credit facility ~~to $190 million, and further reducing on a quarterly basis to $125 million for the quarter beginning January 1, 2019.~~

~~Second Lien Term Loan Agreement~~

On April 12, 2017, we entered into a new $40 million second lien senior secured term loan facility with our wholly-owned subsidiaries Emerge Energy Services Operating LLC and Superior Silica Sands LLC, as borrowers (the “Borrowers”) and U.S. Bank National Association as disbursing agent and collateral agent (the “Second Lien Term Loan Agreement”). The Second Lien Term Loan Agreement matures on April 12, 2022. Proceeds of the new term credit facility were usedis available to (i) ~~pay down a portion of the our~~refinance existing ~~revolving credit facility,~~indebtedness, (ii) fund ~~the asset acquisition described in Note 2 (iii) pay~~ fees and expenses incurred in connection with the ~~new term~~ credit facility and ~~(iv)~~(iii) for general business ~~purposes. Substantially all of our assets are pledged as collateral on a second lien basis under the Second Lien Term Loan Agreement.~~purposes, including working capital requirements, capital expenditures, permitted acquisitions, making debt payments when due, and making distributions and dividends.

The ~~Second Lien Term Loan~~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, ~~an interest~~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 ~~not less than 1.70:~~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 three months ended March 31, 2018, we wrote off $3.9 million of deferred financing costs relating to the reduction of our revolving credit facility.

As of March 31, 2018, our outstanding borrowings under the Credit Agreement bore interest at a rate of 7.8%.

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 million second lien note purchase agreement with the purchasers thereunder (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 ~~increasing~~decreasing quarterly thereafter to ~~2.55:~~3.00:1.00 for the fiscal quarter ending March 31, 2019, and thereafter;

beginning with the fiscal quarter ending ~~June 30, 2017,~~March 31, 2018, a minimum ~~EBITDA~~fixed charge coverage ratio of ~~not less than $637,500 for such fiscal quarter,~~1.10:1.00, increasing quarterly to ~~$50 million~~2.00:1.00 for the ~~four~~ fiscal quarter ~~period~~ ending ~~June 30,~~March 31, 2019, and thereafter; and

~~minimum excess~~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 ~~at least $12.75~~the original principal amount. Accordingly, on March 31, 2018, we have classified $8.1 million ~~so long~~of principal as ~~the Revolving Credit Agreement remains in effect.~~a current liability.

~~Loans~~The notes under the Second Lien ~~Term Loan~~Note Purchase Agreement ~~will~~ bear interest at 11.0% per annum until December 31, 2018, and ranging from 10.00% per annum to 12.00% per annum thereafter, depending on the ~~Partnership’s option~~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.

As of March 31, 2018, borrowings under the Second Lien Note Purchase Agreement bore interest at ~~either the base~~a rate ~~plus 9.00%, or LIBOR plus 10.00%~~of 11.0%.

Covenants Compliance

At ~~June 30, 2017,~~March 31, 2018, we were in compliance with our loan covenants and had undrawn availability under the Credit Agreement totaling ~~$43.6~~$53.5 million, well above the minimum availability required under our current covenants. Our outstanding borrowings under the Credit Agreement bore interest at a weighted-average rate of 6.51% and the borrowings under the Second Lien Term Loan Agreement bore interest at a weighted-average rate of 11.16%.

6.5. RELATED PARTY TRANSACTIONS

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

Six Months Ended June 30,
2017 2016

($ in thousands)
Wages and employee-related costs (1) $ 8,263
$ 5,114

~~Wages and employee-related costs for discontinued operations for June 30, 2016 was $4.0 million.~~



	Three Months Ended March 31,
	2018		2017

	($ in thousands)
Employee-related and other costs (1)	$	9,286	$	4,076


	June 30, 2017		December 31, 2016		March 31, 2018		December 31, 2017

	($ in thousands)				($ in thousands)
Accounts receivable	$	—	$	371
Accounts receivable, net					$	2	$	962
Accounts payable and accrued liabilities	$	574	$	436	$	351	$	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.

7.6. 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, and~~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 ~~55-month~~67-month vesting period, which represents management’s estimate of the amount of time until all vesting conditions have been met. ~~Concurrent with the closing of a secondary offering in June 2014 and the exercise of the underwriters’ over-allotment in July 2014, 90,686 of these phantom units vested and common units were issued.~~ For other phantom units granted to employees, we ~~assume~~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 following the date of vesting. As of ~~June 30, 2017,~~March 31, 2018, the unpaid liability for distribution equivalent rights totaled $0.8 million.

In ~~2017,~~the first quarter of 2018, we granted ~~31,750~~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 ~~to three~~ years.

The following table summarizes awards granted during the ~~six~~three months ended ~~June 30, 2017.~~March 31, 2018.


	Total Units		Phantom Units		Restricted Units		Fair Value per Unit at Award Date		Total Units		Phantom Units		Restricted Units	Fair Value per Unit at Award Date
Outstanding at December 31, 2016	289,607		213,851		75,756		$	13.09
Outstanding at December 31, 2017									333,821		310,780		23,041	$	13.10
Granted	54,791		31,750		23,041		$	12.76	24,800		24,800		—	$	6.98
Vested	(91,156	)	(15,400	)	(75,756	)	$	11.75	(25,275	)	(25,275	)	—	$	9.72
Forfeitures	(12,000	)	(12,000	)	—		$	—	—		—		—	$	—
Outstanding at June 30, 2017	241,242		218,201		23,041		$	13.30
Outstanding at March 31, 2018									333,346		310,305		23,041	$	12.90

For the ~~six~~three months ended ~~June 30,~~March 31, 2018, and 2017, ~~and 2016,~~ we recorded non-cash equity-based compensation expense of ~~$0.7~~$0.4 million and ~~$0.1~~$0.3 million, respectively, in selling, general and administrative expenses. ~~Non-cash equity-based compensation expense for continuing operations was $(0.1) million for the six months ended June 30, 2016.~~

As of ~~June 30, 2017,~~March 31, 2018, the unrecognized compensation expense related to the grants discussed above amounted to ~~$1.6~~$1.5 million to be recognized over a weighted average of ~~0.90~~1.09 years.

8.7. INCOME TAXES

~~Continuing operations~~

Our provision for income taxes ~~for continuing operations~~ relates to: (i) Texas margin taxes for the Partnership, and (ii) ~~an insignificant amount of~~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 ~~for continuing operations~~ is as follows:


	Six Months Ended June 30,				Three Months Ended March 31,
	2017		2016		2018		2017

	($ in thousands)				($ in thousands)
Texas margin tax	$	—	$	20	$	42	$	—
Canadian income tax	—		1		55		—
Total provision for income taxes	$	—	$	21	$	97	$	—

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 ~~0.75%~~0.375% as defined by applicable state law. The margin tax qualifies as an income tax under ~~Generally Accepted Accounting Principles (GAAP),~~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.

9.8. 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 ~~participating securities, and increased further to include~~ the number of common units that would have been outstanding had potential dilutive units been exercised. The dilutive effect of restricted units is reflected in diluted net income per unit by applying the treasury stock method. 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 ~~June 30, 2017~~March 31, 2018, and ~~2016. We exclude all potentially dilutive units from the~~2017.

Basic and diluted earnings per unit ~~calculation~~ for ~~any periods of net loss from continuing operations~~the three months ended March 31, 2018, is calculated as ~~their effect would be anti-dilutive.~~follows:

Three Months Ended June 30, Six Months Ended June 30,
2017 2016 2017 2016
($ in thousands, except unit and per unit data)
Net income (loss) from continuing operations $ (3,425 ) $ (28,150 ) $ (14,815 ) $ (62,591 )
Net income (loss) from discontinued operations (2,657 ) 5,253
(2,657 ) 5,479

Net Income (loss) $ (6,082 ) $ (22,897 ) $ (17,472 ) $ (57,112 )

Weighted average number of common units outstanding - basic and diluted 30,147,725
24,129,418
30,104,613
24,125,320

Basic and diluted earnings (loss) per unit:
Earnings (loss) per common unit from continuing operations $ (0.11 ) $ (1.17 ) $ (0.49 ) $ (2.59 )
Earnings (loss) per common unit from discontinued operations (0.09 ) 0.22
(0.09 ) 0.23

Basic and diluted earnings (loss) per common unit $ (0.20 ) $ (0.95 ) $ (0.58 ) $ (2.36 )



	Three Months Ended March 31,
	2018		2017

	($ in thousands, except per unit data)
Net Income (loss)	$	1,486	$	(11,390	)

Weighted average common units outstanding	30,997,125		30,061,022
Weighted average units deemed participating securities	215,843		—
Weighted average number of common units outstanding - basic	31,212,968		30,061,022
Weighted average potentially dilutive units outstanding	15,122		—
Add incremental units from assumed exercise of warrants	143,292		—
Weighted average number of common units outstanding - diluted	31,371,382		30,061,022

Basic earnings (loss) per common unit	$	0.05	$	(0.38	)

Diluted earnings (loss) per common unit	$	0.05	$	(0.38	)

~~10.~~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.

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

Agreement Date Effective Date Maturity Date Notional Amount Fixed Rate Variable Rate
Nov. 1, 2013 Oct. 14, 2014 Oct. 16, 2017 $25,000,000 1.33200% 1 Month LIBOR
Nov. 7, 2013 Oct. 14, 2014 Oct. 16, 2017 $25,000,000 1.25500% 1 Month LIBOR
Nov. 21, 2013 Oct. 14, 2014 Oct. 16, 2017 $20,000,000 1.21875% 1 Month LIBOR

The Fuel business utilized financial hedging arrangements whereby we hedged a portion of our gasoline and diesel inventory, which reduced our commodity price exposure on some of our activities. The derivative commodity instruments we utilized consisted mainly of futures traded on the New York Mercantile Exchange. Following the sale of the Fuel business, we have no open commodity derivative contracts.

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). The resulting gains and losses for the Fuel business were recorded to cost of goods sold for discontinued operations (for derivative commodity instruments), as reported in the condensed consolidated statements of operations. Our derivative instruments serve the same risk management purpose whether designated as a hedge or not. We derive fair values principally from published market interest rates ~~and fuel price quotes~~ (Level 2 inputs). ~~The precise level of open position commodity derivatives is dependent on inventory levels, expected inventory purchase patterns, and market price trends.~~ We do not use derivative financial instruments for trading or speculative purposes.

On August 8, 2016, we, as part of the private placement described above, ~~also~~ issued a warrant to the ~~Purchaser~~purchaser to purchase approximately 890,000 common units at an exercise price of $10.82 per common unit. The ~~Warrant~~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 ~~$3.0~~$0.7 million and ~~$2.3~~a loss of $0.7 million during the three ~~and six~~ months ended ~~June 30, 2017.~~March 31, 2018, and 2017, respectively.

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

June 30, 2017 December 31, 2016 Classification

($ in thousands)
Interest rate swaps $ 13
$ 227
Accrued liabilities
Warrant liability $ 4,707
$ 7,019
Other long-term liabilities



	March 31, 2018		December 31, 2017		Classification

	($ in thousands)
Warrant liability	$	2,134	$	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 June 30,					Six Months Ended June 30,						Three Months Ended March 31,
	2017			2016		2017			2016		Classification	2018			2017			Classification

	((income) expense $ in thousands)											((income) expense $ in thousands)
Interest rate swaps	$	(8	)	$	152	$	(64	)	563		Interest expense, net	$	—		$	(56	)	Interest expense, net
Commodity derivative contracts	—			682		—			701		Income from discontinued operations
Warrant	(3,008		)	—		(2,312		)	—		Other expense (income)	(677		)	696			Other expense (income)
	$	(3,016	)	$	834	$	(2,376	)	$	1,264		$	(677	)	$	640

~~11.~~10. SUPPLEMENTAL CASH FLOW DISCLOSURES

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


	Six Months Ended June 30,					Three Months Ended March 31,
	2017		2016			2018		2017

	($ in thousands)					($ in thousands)
Cash paid for interest	$	6,934	$	11,438		$	3,359	$	2,921
Cash paid for income taxes, net of refunds	$	15	$	(67	)	$	—	$	15
Issuance of equity						$	5,974	$	—
Purchases of PP&E accrued but not paid at period-end	$	1,115	$	180		$	3,210	$	1,561
Purchases of PP&E accrued in a prior period and paid in the current period	$	170	$	3,364		$	11,372	$	170

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

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 ~~(collectively “Insight Equity”)~~ to own, operate, acquire and develop a diversified portfolio of energy service assets.

The results of operations of the Fuel business have been classified as discontinued operations for all periods presented and we now operate our continuing business in a single Sand business. Through our Sand business, we are engaged in the businesses of mining, processing, and distributing silica sand, a key input for the hydraulic fracturing of oil and gas wells. We conduct our Sand operations through our subsidiary SSS, and we believe our SSS brand has name recognition and enjoys a positive reputation with our customers.

On April 12, 2017, we closed the transaction to acquire substantially all of the assets of Osburn Materials for $20 million. The transaction was funded with a new $40 million term loan, and the remaining proceeds (after transaction fees and expenses) were used to reduce outstanding borrowings under the revolving credit facility. Osburn Materials is located approximately 25 miles south of San Antonio, Texas and produces and sells sand and construction materials but did not serve the energy markets. We

upgraded the existing operations for conversion into frac sand sales and commenced frac sand production in July 2017. Osburn Materials’ current sand reserves, which consists mostly of 40/70 and 100 mesh fine mesh, meets API specifications for all grades.

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, ~~2016,~~2017, as well as historical condensed consolidated financial statements and notes included elsewhere in this Quarterly Report.

Results of Operations

The following table summarizes our consolidated operating ~~results.~~results:


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended March 31,
	2017			2016			2017			2016			2018			2017

	($ in thousands)												($ in thousands)
Revenues	$	82,602		$	24,825		$	157,946		$	54,495		$	106,750		$	75,344

Operating expenses:
Cost of goods sold (excluding depreciation, depletion and amortization)	71,428			38,354			143,739			82,144			80,242			72,311
Depreciation, depletion and amortization	5,675			4,870			10,331			9,777			4,861			4,656
Selling, general and administrative expenses	6,850			4,459			12,728			11,234			8,571			5,878
Contract and project terminations	—			10			—			4,036			1,689			—
Total operating expenses	83,953			47,693			166,798			107,191			95,363			82,845
Operating income (loss)	(1,351		)	(22,868		)	(8,852		)	(52,696		)	11,387			(7,501		)
Other expense (income):
Interest expense	5,082			5,283			8,280			9,877			10,492			3,198
Other	(3,008		)	(2		)	(2,317		)	(3		)	(688		)	691
Total other expense	2,074			5,281			5,963			9,874			9,804			3,889
Income (loss) before provision for income taxes	(3,425		)	(28,149		)	(14,815		)	(62,570		)	1,583			(11,390		)
Provision (benefit) for income taxes	—			1			—			21			97			—
Net income (loss) from continuing operations	(3,425		)	(28,150		)	(14,815		)	(62,591		)
Income (loss) from discontinued operations, net of taxes	(2,657		)	5,253			(2,657		)	5,479
Net income (loss)	$	(6,082	)	$	(22,897	)	$	(17,472	)	$	(57,112	)	$	1,486		$	(11,390	)

Adjusted EBITDA (a)	$	7,534		$	(9,080	)	$	7,602		$	(18,593	)	$	17,386		$	68

(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

Beginning in late 2014, the market prices for crude oil and refined products began a steep and protracted decline which continued into 2016. This greatly impacted the demand for frac sand as drilling and completion of new oil and natural gas wells was significantly curtailed in North America. As a result, we experienced significant downward pressure on sand volume and pricing. However, commodity prices stabilized in the middle of 2016, leading to an improvement in drilling activity during the third quarter of 2016 and into 2017. Market conditions have ~~improved significantly~~continued to improve in the ~~first half of 2017,~~current environment, and based on industry outlooks from ~~third party~~third-party research firms and customers, we expect conditions to ~~continue to improve~~remain strong for ~~the rest of the year and into~~ 2018.

The increase in demand for frac sand has significantly tightened the availability of supply, and as a result, customers are seeking surety of supply through contractual commitments. We are ~~now~~ selectively agreeing toand entering into multi-year contracts with some of our key accounts. ~~For example, we recently entered into a three year,~~We are also executing take-or-pay sand supply ~~agreement with~~agreements for our San Antonio operation and have received a ~~customer whereby we are compensated at a fixed price per ton if less than~~number of non-binding indications of interest for the ~~minimum volume of sand committed for sale under the agreement is ultimately purchased by the customer.~~product. We believe ~~this ensures~~that sand supply agreements ensure the customers a steady supply of product in exchange for covering the infrastructure-related fixed costs plus needed margins associated with operating our business.

Although the near-term supply is closely aligned to current demand, our competitors have begun building in-basin frac sand operations targeting the Permian Basin in West Texas Permian Basin. Our Osburn Materials transaction positions us to target other under-served Texas in-basin markets with comparatively less start-up costs (e.g., permitting, construction, infrastructure, and ~~environmental analyses).~~the Eagle Ford basin in South Texas. There can be no assurances that all of the announced projects will be completed given permitting, construction, infrastructure, and environmental constraints.

~~Sale of Fuel Business~~

~~In order~~ Our San Antonio operation positions us to ~~improve our competitive positioning~~target the second most active Texas in-basin market with comparatively less start-up costs (e.g., permitting, construction, infrastructure, and retain upside for the eventual recovery in the oil and gas cycle, we divested our Fuel business to reduce our debt burden. We recorded a gain of $31.7 million on the sale of the Fuel business during the third quarter of 2016. Please see Note 3 to our financial statements for a detailed discussion of the sale of the Fuel business.environmental analysis).

Expansion of Sand Resources

On April 12, 2017, we closed the transaction to acquire ~~substantially all of the assets of Osburn Materials~~our San Antonio operations for ~~approximately~~ $20 million. ~~Osburn Materials~~The San Antonio site is located approximately 25 miles south of San Antonio, Texas and ~~produces~~previously produced and ~~sells~~sold construction, foundry and sports sands, ~~and building products,~~ but did not serve the energy markets. We upgraded the existing operations for conversion into frac sand ~~sales~~production and commenced frac sand production in July 2017. ~~Osburn Materials has~~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, and the wet plant is targeted to be operational in July 2018. Our San Antonio reserves contain API-specification, strategic reserves (40/70 and100 mesh sands) that ~~will~~ 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 basin, 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.

Fluctuating Fixed Costs for Sand

During 2014, our rapidly expanding frac sand business required us to contract for numerous railcars to be delivered and leased in the future as well as contracting for new transload ~~facilities discussed above.~~facilities. The industry downturn from 2015 through 2016 and the corresponding decline in volumes shipped created an excess number of railcars in our fleet, increasing our fixed costs ~~per ton.~~per-ton. However, we successfully negotiated concessions with several of our vendors, ~~in 2016,~~ and the ~~recent~~significant upturn in frac sand demand has required us to place most of our idled railcars back into service, thereby reducing our fixed cost per ton.

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. 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 recent acquisition in San Antonio, we have two Texas operations that are well positioned geographically to meet the strong demand in the prolific Texas basins.

~~Cost Containment~~

To conserve liquidity and respond to the industry downturn, we became focused on prudently reducing costs while maintaining our ability to quickly respond to market demands. We have already implemented plans, but will continue to aggressively contain costs in the future. Such measures include:

~~We are minimizing the overall cost of sand sold by finding the lowest cost combinations of sand source, production location and transportation providers wherever possible.~~

We have negotiated, and continue to negotiate, price concessions and purchase commitment concessions from our major vendors, such as railcar lessors, rail transportation providers, mine operators, transload facilities operators, and professional services providers.

~~We have minimized our capital expenditures to include only those projects with the potential for rapid returns, and comply with our bank covenants that limit capital expenditures.~~

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 ~~in-basin~~terminal sales than for ~~FOB-plant~~FOB plant sales to provide this additional service and convenience to our customers and to cover related transportation and other services costs.

Currently, our northern white sand volumes are partially constrained by railroad congestion from ~~the~~certain class I carriers due to the high volume of shipments that have surpassed prior peak periods. We are working closely with our logistics partners to resolve the bottlenecks during this period of surging ~~demand.~~demand, and we are increasing shipments on newly expanded rail outlets.

Technology Driven Proppant Products

In ~~November 2015,~~early 2016, we ~~acquired 11 patents and other intellectual property assets from AquaSmart Enterprises LLC for their Self-Suspending Sand technology. The product~~launched our self-suspending sand marketed under the brand ~~is marketed as~~ SandMaxX™. ~~While subject to ongoing field testing that began in 2016 and data validation, this~~This new technology offers the potential to increase ~~productivity and completion efficiencies~~production in oil and gas wells ~~while~~in addition to improving pump time and ~~well site economics. At our Barron dry plant,~~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 ~~a pilot production circuit~~elected to produce in excess of 175,000 tons per year of SandMaxX™ product. This pilot production circuit uses proprietary and patented technology to coat all grades of standard frac sand. SandMaxX™ product was pumped downhole in multiple trial wells during 2016 and 2017, and while the early results appear favorable, we are working closely with our customers to confirm and document actual well performance data in addition to comparing the results against wells completed with regular sand. Our plans for constructing a commercial scale coating plant depend upon the successful completiondiscontinue ownership of the ~~field trial testing and achieving market acceptance~~intellectual property after the initial installment period. This will not have a material impact on our financial position or results of the product. We will continue to work toward transforming our Sand business from a commodity business to a more value-driven approach by developing capabilities and products that enable us to increase our presence in larger, more profitable markets.operations.

~~Continuing Operations~~

Operating results


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended March 31,
	2017			2016			2017			2016			2018		2017

	($ in thousands)												($ in thousands)
Revenues	$	82,602		$	24,825		$	157,946		$	54,495
Revenues:
Frac sand revenues													$	105,971	$	75,182
Non-frac sand revenues													779		162
Total revenues													106,750		75,344
Operating expenses:
Cost of goods sold (excluding depreciation, depletion and amortization)	71,428			38,354			143,739			82,144			80,242		72,311
Depreciation, depletion and amortization	5,675			4,870			10,331			9,777			4,861		4,656
Selling, general and administrative expenses	6,850			4,459			12,728			11,234			8,571		5,878
Contract and project terminations	—			10			—			4,036			1,689		—
Operating income (loss)	$	(1,351	)	$	(22,868	)	$	(8,852	)	$	(52,696	)	$	11,387	$	(7,501	)
Net income (loss) from continuing operations	$	(3,425	)	$	(28,150	)	$	(14,815	)	$	(62,591	)	$	1,486	$	(11,390	)
Adjusted EBITDA (a)	$	7,534		$	(16,028	)	$	7,602		$	(29,010	)	$	17,386	$	68

Volume of frac sand sold (tons in thousands)	1,284			392			2,529			815			1,437		1,245
Volume of non - frac sand sold (tons in thousands)	108			7			114			23
Volume of non-frac sand sold (tons in thousands)													66		6
Total volume of sand sold (tons in thousands)	1,392			399			2,643			838			1,503		1,251

Volume of frac sand produced by plant (tons in thousands) (b):
Terminal sand sales (tons in thousands)													655		588

Volume of frac sand produced by plant (tons in thousands):
Arland, Wisconsin facility	508			—			876			—			407		368
Barron, Wisconsin facility	518			391			1,050			711			498		532
New Auburn, Wisconsin facility	302			11			619			180			345		317
Kosse, Texas facility	47			26			112			43			99		65
San Antonio, Texas facility (b)													59		—
Total volume of frac sand produced	1,375			428			2,657			934			1,408		1,282

(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 inat the San Antonio facility in July 2017.

Three Months Ended ~~June 30, 2017~~March 31, 2018 Compared to Three Months Ended ~~June 30,~~March 31, ~~2016~~2017

Revenues

Sand revenues increased by ~~$57.8~~$31.4 million primarily due to a ~~249%~~20.1% increase in total volumes sold as a result of the increased market demand for frac sand, ~~and~~as well as higher prices of frac sand in ~~2017~~2018 compared to ~~2016.~~2017. FOB plant sales volumes increased ~~397%~~28% compared to ~~a 139%~~an 11% increase for the higher-priced, ~~in-basin~~terminal sand sales. ~~In-basin~~Terminal sales as a percentage of total volumes sold decreased from ~~57%~~47% in ~~the second quarter of 2016~~2017 to ~~39%~~44% in ~~the second quarter of 2017. The shift in the mix of FOB plant and in-basin volumes decreased the overall revenue~~2018. Revenue per ton ~~even though~~increased to $71.02 in 2018 compared to $60.23 per ton in 2017 due to significant price increases.

The major changes from 2017 to 2018 are as follows:

$16.9 million increase in sales of northern white sand (excluding estimated transportation markups), relating primarily to an 8% increase in volumes sold as well as increased pricing in light of market conditions for frac sand;

an estimated $8.2 million increase for significant increases in markups per ton sold through transload sites, along with increased volumes sold through these sites; and

$6.3 million increase in sales of native Texas sand (excluding estimated transportation markups), due to the addition of our San Antonio operation in July 2017, and increased volumes and ~~sand~~ prices ~~increased in 2017.~~at our Kosse facility.

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 increased with our increased sales. The most significant components of the ~~$33.1~~$7.9 million increase from 2017 to 2018 are:

$~~16.3~~7.5 million increase in the total cost to acquire and produce ~~wet and dry~~ sand due ~~mainly~~ to ~~higher sales volumes;~~

~~$15.3 million~~20% increase in ~~rail transportation-related expense, primarily due to:~~total volumes sold;

$~~16.3 million increased rail shipping costs due to increased volumes sold in-basin; offset by~~

~~$0.8 million decreased rail lease expense; and~~

~~$0.2 million decreased railcar storage costs;~~

~~$1.4~~0.6 million increase in costs of transload ~~facilities.~~facilities due to increased volumes; and

$0.2 million decrease in rail transportation-related expense resulting primarily from decreased railcar storage costs as we have placed previously stored cars back into service.

Selling, general and administrative expenses

The ~~$2.4~~$2.7 million increase in selling, general and administrative expenses is attributable primarily to:

$~~1.8~~1.3 million increase in employee-related costs due to higher staffing and bonus accruals; and

$~~0.5~~1.1 million expenses related to the long-term debt refinancing in January 2018.

Interest expense

Net interest expense increased $7.3 million primarily due to;

$5.7 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 ~~equity-based compensation expense.~~January 2018; offset by

$2.1 million decreased interest expense due to the reduction of outstanding balances under the revolving credit facility.

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.

Other

Other expenses decreased ~~$3.0~~$1.4 million due to a mark-to-market gain of $0.7 million recognized in the ~~second~~first quarter of 2018, compared to a loss of $0.7 million recognized in the first quarter of 2017, ~~for~~due to a change in the fair value of the warrant issued in August 2016.

~~Six Months Ended June 30, 2017 Compared to Six Months Ended June 30,~~ ~~2016~~

~~Revenues~~

Sand revenues increased by $103.5 million, primarily due to a 215% increase in total volumes sold as a result of the increased market demand for frac sand and higher prices of frac sand in 2017 compared to 2016. FOB plant sales volumes increased 343% compared to a 128% increase for the higher-priced in-basin sand sales. In-basin sales as a percentage of total volumes sold decreased from 59% in the six months of 2016 to 43% in the six months of 2017. The shift in the mix of FOB plant and in-basin volumes decreased the overall revenue per ton, even though volumes and sand prices increased in 2017.

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

$21.5 million increase in the total cost to acquire and produce wet and dry sand, due mainly to higher sales volumes, and higher production costs on a per ton basis due to costs incurred to start the wet plants back up from the winter months;

~~$31.9 million increase in rail transportation-related expense, primarily due to:~~

~~$35.4 million increased rail shipping costs due to increased volumes sold in-basin; offset by~~

~~$2.7 million decreased rail lease expense; and~~

~~$0.9 million decreased railcar storage costs;~~

~~$2.8 million increase in costs of transload facilities; and~~

$5.4 million write down of sand inventory in the first quarter of 2016 based on our lower of cost or market analysis. This write down is attributed to declining market conditions and a significant decline in prices.

~~Selling, general and administrative expenses~~

~~The $1.5 million increase in selling, general and administrative expenses is attributable primarily to:~~

~~$2.1 million increase in employee-related costs due to higher staffing and bonus accruals;~~

~~$0.6 million in increased equity-based compensation expense;~~

~~$0.4 million increase in outside professional services, offset by~~

~~$1.7 million decrease in bad debt expense.~~

~~Interest expense~~

Net interest expense decreased $1.6 million mainly due to lower average balances on outstanding revolving credit facility, offset by the addition of the second lien term loan and higher average interest rates in 2017.

~~Other~~

~~Other expenses decreased $2.3 million due to a mark-to-market gain recognized in 2017 for a change in the fair value of the warrant issued in August 2016.~~

~~Contract and project terminations~~

During the first half of 2016, we negotiated various railcar lease contracts. As part of these negotiations, we paid $4.0 million as contract termination fees to a railcar lease vendor. See Note 4 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 did not have any operations for the Fuel business in 2017.~~

~~During the three months ended June 30, 2017, we wrote off a non-cash charge of $2.7 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, ~~including~~finance acquisitions from time to time, to service our debt and to pay distributions to partners. Our sources of liquidity generally include cash generated by our operations, borrowings under our revolving ~~Credit Agreement~~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. WeFollowing our entry into the Credit Agreement and the Second Lien Note Purchase Agreement (described below), we believe that cash generated 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 $70 million and $90 million in capital expenditures to fund the expansion of our San Antonio operation and finance various capital projects that offer attractive rates of return.

Revolving Credit Facility

~~Pursuant to Amendment No. 11, the Credit Agreement now requires the Partnership to maintain the following financial covenants:~~

~~a covenant to maintain $15 million of excess availability (as defined in the Credit Agreement);~~

~~a covenant to limit capital expenditures (as defined in the Credit Agreement) to certain maximum amounts for each quarter through March 31, 2019;~~

~~beginning with the quarter ending June 30, 2017, a covenant to generate consolidated EBITDA (as defined in the Credit Agreement) in certain minimum amounts;~~

~~We believe that we will be able to maintain compliance with the covenants and restrictions under the Credit Agreement, as amended, for at least the next 12 months.~~

~~Second Lien Term Loan Agreement~~

On April 12, 2017, we entered into a new $40 million second lien senior secured term loan facility with our wholly-owned subsidiaries Emerge Energy Services Operating LLC and Superior Silica Sands LLC, as borrowers (the “Borrowers”) and U.S. Bank National Association as disbursing agent and collateral agent (the “Second Lien Term Loan Agreement”). The Second Lien Term Loan Agreement matures on April 12, 2022. Proceeds of the new term credit facility were usedis available to (i) ~~pay down a portion of the our~~refinance existing ~~revolving credit facility,~~indebtedness, (ii) fund ~~the acquisition described in Note 2, (iii) pay~~ fees and expenses incurred in connection with the ~~new term~~ credit facility and ~~(iv)~~(iii) for general business ~~purposes. Substantially all of our assets are pledged as collateral on a second lien basis under the Second Lien Term Loan Agreement.~~purposes, including working capital requirements, capital expenditures, permitted acquisitions, making debt payments when due, and making distributions and dividends.

The ~~Second Lien Term Loan~~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 minimum fixed charge coverage ratio of ~~not less than 1.70:~~1.10:1.00; and

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

Second Lien Note Purchase Agreement

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;

~~minimum excess~~a limit on capital expenditures, subject to certain availability thresholds.

Covenants Compliance

At ~~June 30, 2017,~~March 31, 2018, we were in compliance with our loan ~~covenants and had undrawn availability totaling $43.6 million under the Credit Agreement, well above the minimum availability required under our current~~ covenants. Our outstanding borrowings under the Credit Agreement bore interest at a weighted-average rate of 6.51% and the borrowings under the Second Lien Term Loan Agreement bore interest at a weighted-average rate of 11.16%.

Liquidity Trends

Beginning in ~~the second half of~~late 2014 and continuing through the middle of 2016, prices for natural gas, crude oil and refined fuels were extremely volatile and decreased significantly. Although oil and gas drilling and completions activity has improved significantly in the last ~~12 months,~~two years, our cash flows from operating activities are subject to significant quarterly variations as volatile commodity prices influence demand for our frac sand. In addition, after closing the sale of our Fuel business we are more dependent on the volatility in demand for frac sand without the benefit of cash flows generated by our Fuel business in periods of stable commodity prices. Therefore, the cash generated by our operations are driven by a number of factors beyond our control, including global and regional product supply and demand, weather, product distribution, refining and processing capacity and other supply chain dynamics, among other factors. 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.

However, our ability to comply with the restrictions and covenants of the Credit Agreement and the Second Lien ~~Term Loan~~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. If in the future we are unable to comply with the financial covenants of the Credit Agreement and the Second Lien Note Purchase Agreement and the lenders are unwilling to provide us with additional flexibility or a waiver, we may be forced to repay or refinance amounts then outstanding under the Credit Agreement and 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.

Cash Flow Summary

The table below summarizes our cash ~~flows.~~flows:


	Six Months Ended June 30,						Three Months Ended March 31,
	2017			2016			2018			2017

	($ in thousands)						($ in thousands)
Cash flows from operating activities	$	(7,173	)	$	(13,032	)	$	10,744		$	(12,939	)
Cash flows from investing activities	$	(23,622	)	$	(11,012	)	$	(30,093	)	$	(1,392	)
Cash flows from financing activities	$	30,980		$	6,332		$	22,309		$	16,426
Cash and cash equivalents at beginning of period	$	4		$	20,870		$	5,729		$	4
Cash and cash equivalents at end of period	$	189		$	3,158		$	8,689		$	2,099

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. ~~The~~Significant changes in our ~~operating assets~~working capital resulted from rapid growth of sales and ~~liabilities were also significantly impacted~~billings to support our expanding business, offset by ~~higher accounts receivable~~lower inventory balances ~~resulting from higher sales of sand and higher prices~~ during the first ~~six~~three months of ~~2017.~~2018.

Investing cash flows

Cash flows used in investing activities increased during the ~~six~~three months ended ~~June 30, 2017~~March 31, 2018, due to the acquisition of assets from Osburn Materials offset by decrease in our capital expenditures. Capital expenditures in the first six months of 2016 related to the Fuel business. Additionally, as a resultconstruction of the ~~current market conditions and covenants under our Credit Agreement, we have~~San Antonio plants. We had significantly curtailed our capital expenditures to ~~include only those projects with the potential for rapid returns, and~~ comply with our bank covenants that ~~limit~~limited capital ~~expenditures.~~expenditures during the three months ended March 31, 2017.

Financing cash flows

Our cash balance as of ~~June 30, 2017 is $0.2~~March 31, 2018, was $8.7 million compared to ~~$4,000~~$5.7 million as of December 31, ~~2016~~2017, and ~~$3.2~~$2.1 million as of ~~June 30, 2016.~~March 31, 2017. During 2017, We ~~are currently~~were subject to a cash dominion requirement as per Amendment No. 11 to our Prior Credit Agreement, which ~~requires~~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 ~~manage~~maintained a minimal cash balance and managed our cash on a daily basis and ~~make~~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:


	Six Months Ended June 30,						Three Months Ended March 31,
	2017			2016			2018			2017

	($ in thousands)						($ in thousands)
Net debt proceeds (payments)	$	35,824		$	10,894		$	34,928		$	18,171
Payment of financing costs							(11,964		)	(163		)
Other	(4,844		)	(4,562		)	(655		)	(1,582		)
Total	$	30,980		$	6,332		$	22,309		$	16,426

In ~~April 2017,~~January 2018, we entered into athe 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 ~~loan for $40 million. Proceeds of the new term~~ credit facility, ~~were used~~(ii) to ~~(i)~~fully pay ~~down a portion of~~off the ~~our~~obligations under the Partnership’s existing revolving credit facility, ~~(ii) fund the acquisition described in Note 2~~ (iii) to finance capital expenditures, (iv) to pay fees and expenses incurred in connection with the new ~~term credit~~second lien facility and ~~(iv)~~(v) for general business purposes.

~~Critical Accounting Estimates~~

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 acquisition to the assets acquired on a relative fair value basis at the acquisition date. The preliminary 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. Additionally, we are finalizing the sand reserves estimates. Transaction costs incurred for the acquisition are capitalized as a component of the cost of the assets acquired.

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.

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

The following table ~~present a reconciliation of~~reconciles net income (loss) to Adjusted EBITDA for the three months ended ~~June 30, 2017~~March 31, 2018, and ~~2016:~~2017:

Continuing Discontinued Consolidated

Three Months Ended June 30,
2017 2016 2017 2016 2017 2016

($ in thousands)
Net income (loss) $ (3,425 ) $ (28,150 ) $ (2,657 ) $ 5,253
$ (6,082 ) $ (22,897 )
Interest expense, net 5,082
5,283
—
686
5,082
5,969

Depreciation, depletion and amortization 5,675
4,870
—
—
5,675
4,870

Provision for income taxes —
1
—
5
—
6

EBITDA 7,332
(17,996 ) (2,657 ) 5,944
4,675
(12,052 )
Equity-based compensation expense 330
(335 ) —
131
330
(204 )
Contract and project terminations —
10
—
—
—
10

Reduction in escrow receivable —
—
2,657
—
2,657
—

Provision for doubtful accounts —
—
—
38
—
38

Accretion expense 29
30
—
—
29
30

Retirement of assets 66
—
—
67
66
67

Fuel division selling expenses —
—
—
679
—
679

Other state and local taxes 456
483
—
89
456
572

Non-cash deferred lease expense 2,329
1,607
—
—
2,329
1,607

Unrealized gain on fair value of warrant (3,008 ) —
—
—
(3,008 ) —

Other adjustments allowable under our Credit Agreement —
173
—
—
—
173

Adjusted EBITDA $ 7,534
$ (16,028 ) $ —
$ 6,948
$ 7,534
$ (9,080 )

~~The following table present a reconciliation of net income (loss) to Adjusted EBITDA for the six months ended June 30, 2017 and 2016:~~


	Continuing						Discontinued					Consolidated
																		Three Months Ended March 31,
	Six Months Ended June 30,																	2018			2017
	2017			2016			2017			2016		2017			2016
	($ in thousands)																	($ in thousands)
Net income (loss)	$	(14,815	)	$	(62,591	)	$	(2,657	)	$	5,479	$	(17,472	)	$	(57,112	)	$	1,486		$	(11,390	)
Interest expense, net	8,280			9,877			—			1,283		8,280			11,160			10,492			3,198
Depreciation, depletion and amortization	10,331			9,777			—			2,354		10,331			12,131			4,861			4,656
Provision for income taxes	—			21			—			11		—			32
Provision (benefit) for income taxes																		97			—
EBITDA	3,796			(42,916		)	(2,657		)	9,127		1,139			(33,789		)	16,936			(3,536		)
Equity-based compensation expense	677			(98		)	—			234		677			136			434			347
Write-down of sand inventory	—			5,394			—			—		—			5,394
Contract and project terminations	—			4,036			—			—		—			4,036			1,689			—
Reduction in escrow receivable	—			—			2,657			—		2,657			—
Provision for doubtful accounts	—			1,672			—			74		—			1,746			3			—
Accretion expense	58			59			—			—		58			59			31			29
Retirement of assets	60			—			—			67		60			67			2			(6		)
Reduction in force	—			76			—			—		—			76
Fuel division selling expenses	—			—			—			679		—			679
Other state and local taxes	880			952			—			236		880			1,188			395			424
Non-cash deferred lease expense	4,230			1,607			—			—		4,230			1,607			(2,576		)	1,901
Unrealized gain on fair value of warrant	(2,312		)	—			—			—		(2,312		)	—
Unrealized (gain) loss on fair value of warrant																		(677		)	696
Other adjustments allowable under our Credit Agreement	213			208			—			—		213			208			1,149			213
Adjusted EBITDA	$	7,602		$	(29,010	)	$	—		$	10,417	$	7,602		$	(18,593	)	$	17,386		$	68

The following table reconciles ~~Consolidated~~ Adjusted EBITDA to our operating cash flows for the three ~~and six~~ months ended ~~June 30, 2017~~March 31, 2018, and ~~2016:~~2017:


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended March 31,

	2017			2016			2017			2016			2018			2017

	($ in thousands)												($ in thousands)
Adjusted EBITDA	$	7,534		$	(9,080	)	$	7,602		$	(18,593	)	$	17,386		$	68
Interest expense, net	(3,975		)	(4,347		)	(6,659		)	(8,989		)	(5,964		)	(2,684		)
Income tax expense	(456		)	(578		)	(880		)	(1,220		)	(493		)	(424		)
Contract and project terminations - non-cash	—			—			—			(25		)
Reduction in force	—			—			—			(76		)
Write-down of sand inventory	—			—			—			(5,394		)
Other adjustments allowable under our Credit Agreement	—			(173		)	(213		)	(208		)	(1,149		)	(213		)
Fuel division selling expenses	—			(679		)	—			(679		)
Permitted acquisition transaction expenses	—			—			—			—
Cost to retire assets	19			9			19			9
Non-cash deferred lease expense	(2,329		)	(1,607		)	(4,230		)	(1,607		)	2,576			(1,901		)
Change in other operating assets and liabilities	4,973			5,714			(2,812		)	23,750			(1,612		)	(7,785		)
Cash flows from operating activities:	$	5,766		$	(10,741	)	$	(7,173	)	$	(13,032	)	$	10,744		$	(12,939	)

Cash flows from investing activities:	$	(22,230	)	$	(6,099	)	$	(23,622	)	$	(11,012	)	$	(30,093	)	$	(1,392	)

Cash flows from financing activities:	$	14,554		$	8,637		$	30,980		$	6,332		$	22,309		$	16,426

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Information about market risks for the ~~six~~three months ended ~~June 30, 2017,~~March 31, 2018, does not differ materially from that discussed under Item 7A of our Annual Report on Form 10-K for the year ended December ~~31,2016.~~31,2017. ~~Following the sale of the Fuel business, risks with respect to prices of refined fuels products and transmix, wholesale fuel and other feedstocks are no longer applicable to or continuing operations.~~

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 ~~June 30, 2017.~~March 31,

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 ~~June 30, 2017~~March 31, 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, ~~2016,~~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 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 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 ~~Limited~~ 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).

~~10.1*†~~ 4.1		~~Sand Supply~~Registration Rights Agreement, dated ~~May 19, 2017,~~January 5, 2018, by and between ~~Superior Silica Sand~~Emerge Energy Services LP, Mezzanine Partners III, L.P., AP Mezzanine Partners III, L.P., EES Offshore, LLC and ~~Liberty Oilfield Service, LLC.~~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).

~~10.2*†~~ 10.1		~~Sand Supply~~Second Amended and Restated Revolving Credit and Security Agreement, dated ~~July 19, 2017, between Superior Silica Sand~~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 ~~EP Energy E&P Company, L.P.~~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.

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: ~~August 4, 2017~~May 3, 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)

~~INDEX TO 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 Limited 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).

~~10.1*†~~		~~Sand Supply Agreement, dated May 19, 2017, between Superior Silica Sand and Liberty Oilfield Service, LLC.~~

~~10.2*†~~		~~Sand Supply Agreement, dated July 19, 2017, between Superior Silica Sand and EP Energy E&P Company, L.P.~~

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.~~



Purchase price	$	167,736
Adjustments:
Working capital true-up	3,398
Other adjustments	(2,911		)
General escrow	(7,000		)
Hydrotreater escrow	(4,000		)
Other escrow	(3,250		)
Net proceeds	153,973
Less:
Net book value of assets and liabilities sold	(125,317		)
Escrow receivable	10,597
Transaction costs including commissions	(7,679		)
Other receivables	125
Gain on sale of Fuel business	$	31,699



Agreement Date	Effective Date	Maturity Date	Notional Amount	Fixed Rate	Variable Rate
Nov. 1, 2013	Oct. 14, 2014	Oct. 16, 2017	$25,000,000	1.33200%	1 Month LIBOR
Nov. 7, 2013	Oct. 14, 2014	Oct. 16, 2017	$25,000,000	1.25500%	1 Month LIBOR
Nov. 21, 2013	Oct. 14, 2014	Oct. 16, 2017	$20,000,000	1.21875%	1 Month LIBOR