UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

Form 10-K

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

For the Fiscal Year Ended December 31, 2018

or

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

For the Transition Period from ____ to ____

Commission File Number: 001-35630

Hi-Crush Partners LP

(Exact name of registrant as specified in its charter)

Delaware	90-0840530
(State or Other Jurisdiction of Incorporation or Organization)	(I.R.S. Employer Identification No.)
1330 Post Oak Blvd, Suite 600
Houston, Texas	77056
(Address of Principal Executive Offices)	(Zip Code)

Registrant’s telephone number, including area code (713) 980-6200

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 partnership interests	New York Stock Exchange

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. þYes ¨No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. ¨Yes þNo

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. þYes ¨No

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files). þYes ¨No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨Yes þNo

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

Large accelerated filer þ	Accelerated filer ¨
Non-accelerated filer ¨	Smaller reporting company ¨
	Emerging growth company ¨

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. ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). ¨Yes þNo

As of June 30, 2018, the last business day of the registrant's most recently completed second fiscal quarter, the aggregate market value of common units held by non-affiliates was approximately $932,956,946 based on the closing price of $11.80 per common unit on that date.

As of February 14, 2019, there were 101,062,399 common units outstanding.

Documents Incorporated by Reference

None.

HI-CRUSH PARTNERS LP

INDEX TO FORM 10-K

	Page
PART I
Item 1. Business	3
Item 1A. Risk Factors	17
Item 1B. Unresolved Staff Comments	38
Item 2. Properties	38
Item 3. Legal Proceedings	42
Item 4. Mine Safety Disclosures	42
PART II
Item 5. Market for Registrant’s Common Units, Related Unitholder Matters and Issuer Purchases of Unit Securities	43
Item 6. Selected Financial Data	44
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	47
Item 7A. Quantitative and Qualitative Disclosures About Market Risk	61
Item 8. Financial Statements and Supplementary Data	62
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	62
Item 9A. Controls and Procedures	62
Item 9B. Other Information	64
PART III
Item 10. Directors, Executive Officers and Corporate Governance	65
Item 11. Executive Compensation	69
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	85
Item 13. Certain Relationships and Related Transactions, and Director Independence	87
Item 14. Principal Accounting Fees and Services	88
PART IV
Item 15. Exhibits, Financial Statement Schedules	90
Item 16. Form 10-K Summary	92

Forward-Looking Statements

Some of the information in this Annual Report on Form 10-K may contain forward-looking statements. Forward-looking statements give our current expectations, contain projections of results of operations or of financial condition, or forecasts of future events. Words such as "may," "should," "assume," "forecast," "position," "predict," "strategy," "expect," "intend," "hope," "plan," "estimate," "anticipate," "could," "believe," "project," "budget," "potential," "likely," or "continue," and similar expressions are used to identify forward-looking statements. They can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed. When considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this Annual Report on Form 10-K. Actual results may vary materially. You are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such risk factors and as such should not consider the following to be a complete list of all potential risks and uncertainties. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include those described under "Risk Factors" in Item 1A of this Annual Report on Form 10-K, and the following factors, among others:

• the potential corporate conversion transaction we are considering may not occur, and even if such transaction were to be completed we may fail to realize the anticipated benefits;

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

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

• demand and pricing for our integrated logistics solutions;

• the pace of adoption of our integrated logistics solutions;

• the amount of frac sand we are able to timely deliver at the wellsite, which could be adversely affected by, among other things, logistics constraints, weather, or other delays at the wellsite or transloading facility;

• changes in prevailing economic conditions, including the extent of changes in crude oil, natural gas and other commodity prices;

• the amount of frac sand we are able to excavate and process, which could be adversely affected by, among other things, operating difficulties, cave-ins, pit wall failures, rock falls and unusual or unfavorable geologic conditions;

• changes in the price and availability of natural gas or electricity;

• inability to obtain necessary equipment or replacement parts;

• changes in the railroad infrastructure, price, capacity and availability, including the potential for rail line disruptions;

• changes in the road infrastructure, including the potential for trucking and other transportation disruptions;

• changes in the price and availability of transportation;

• extensive regulation of trucking services;

• volatility of fuel prices;

• availability of or failure of our contractors, partners and service providers to provide services at the agreed-upon levels or times;

• failure to maintain safe work sites at our facilities or by third parties at their work sites;

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

• environmental hazards, such as leaks and spills as well as unauthorized discharges of fluids or other pollutants into the surface and subsurface environment;

• industrial and transportation related accidents;

• fires, explosions or other accidents;

• difficulty collecting receivables;

• inability of our customers to take delivery;

• difficulty or inability in obtaining, maintaining and renewing permits, including environmental permits or other licenses and approvals such as mining or water rights;

• facility shutdowns or restrictions in operations in response to environmental regulatory actions including but not limited to actions related to endangered species;

• systemic design or engineering flaws in the equipment we use to provide logistics services;

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

• the outcome of litigation, claims or assessments, including unasserted claims;

• challenges to or infringement upon our intellectual property rights;

• labor disputes and disputes with our third-party contractors;

• inability to attract and retain key personnel;

• cyber security breaches of our systems and information technology;

• our ability to borrow funds and access capital markets;

• changes in the foreign currency exchange rates in the countries that we conduct business; and

• changes in the political environment of the geographical areas in which we and our customers operate.

All forward-looking statements are expressly qualified in their entirety by the foregoing cautionary statements. You should assess any forward-looking statements made within this Annual Report on Form 10-K within the context of such risks and uncertainties.

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PART I

ITEM 1. BUSINESS

References in this Annual Report on Form 10-K to the "Partnership," "we," "our," "us" or like terms when used in a historical context to reference operations or matters refer to Hi-Crush Partners LP and its subsidiaries. References in this Annual Report on Form 10-K to "our sponsor" refer to Hi-Crush Proppants LLC, our previous sponsor.

Overview

Hi-Crush Partners LP is a fully integrated, strategic provider of proppant and logistics solutions to the North American petroleum industry. We provide mine-to-wellsite logistics services that optimize proppant supply to customers in all major oil and gas basins in the United States, and own and operate multiple frac sand mining facilities and in-basin terminals. Our PropStream^® service, offering both container- and silo-based wellsite delivery and storage systems, provides the highest level of flexibility, safety and efficiency in managing the full scope and value of the proppant supply chain. 

General

The Partnership is a Delaware limited partnership formed on May 8, 2012. In connection with its formation, the Partnership issued a non-economic general partner interest to Hi-Crush GP LLC, our general partner (the "general partner"), and a 100% limited partner interest to our sponsor, its organizational limited partner.

Corporate Conversion

The board of directors of the general partner unanimously approved a plan of conversion (the "Plan of Conversion") that provides and sets forth matters related to the conversion of the Partnership from a Delaware limited partnership to a Delaware corporation named "Hi-Crush Inc." (the "Conversion"), which, subject to unitholder approval, will be completed through a series of transactions set forth in the Plan of Conversion. Pursuant to the Plan of Conversion, at the effective time of the Conversion, the outstanding common units will each be exchanged for one share of Hi-Crush Inc. common stock, par value $0.01 per share. Holders of common units will receive, in exchange for their common units, 100% of the common stock of Hi-Crush Inc. to be outstanding immediately following the Conversion. As a result of the Conversion, the Partnership will convert from an entity treated as a partnership for U.S. federal income tax purposes to an entity treated as a corporation for U.S. federal income tax purposes.

The Partnership filed a preliminary proxy statement with the U.S. Securities and Exchange Commission ("SEC") on February 5, 2019, which relates to a special meeting at which unitholders will be asked to consider any vote on proposals related to the Conversion. The special meeting of unitholders is expected to be held on April 11, 2019.

Acquisition of Hi-Crush Proppants LLC and Hi-Crush GP LLC

On October 21, 2018, the Partnership entered into a contribution agreement with our sponsor pursuant to which the Partnership acquired all of the then outstanding membership interests in the sponsor and the non-economic general partner interest in the Partnership, in exchange for 11,000,000 newly issued common units (the "Sponsor Contribution"). In connection with the acquisition, all of the outstanding incentive distribution rights representing limited partnership interests in the Partnership were canceled and extinguished and the sponsor waived any and all rights to receive contingent consideration payments from the Partnership or our subsidiaries pursuant to certain previously entered into contribution agreements to which it was a party.

Acquisition of FB Industries Inc.

On July 19, 2018, the Partnership entered into a purchase agreement to acquire FB industries Inc. ("FB Industries"), a company engaged in the engineering, design and marketing of silo-based frac sand management systems. Under the terms of the transaction, the Partnership paid cash consideration of $45.0 million and 1,279,328 newly issued common units to the sellers. The terms also include the potential for additional future consideration payments based on the achievement of established performance benchmarks through 2021. The Partnership completed this acquisition on August 1, 2018.

Assets and Operations

According to John T. Boyd Company, a leading mining consulting firm focused on the mineral and natural gas industries ("John T. Boyd"), our proven reserves at our facilities consist of frac sand exceeding American Petroleum Institute ("API") specifications. Analysis of our sand at our facilities by independent third-party testing companies indicates that the sand demonstrates characteristics exceeding API specifications with regard to crush strength (ability to withstand high pressures), turbidity (low levels of contaminants), roundness and sphericity (facilitates hydrocarbon flow or conductivity), acid solubility and percent quartz (mineralogy).

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Wyeville Facility

We own and operate a 971-acre facility with integrated rail infrastructure, located in Wyeville, Wisconsin (the "Wyeville facility"), which, as of December 31, 2018, contained 72.1 million tons of proven recoverable reserves of frac sand meeting API specifications. The Wyeville facility, completed in 2011 and expanded in 2012, has an annual processing capacity of approximately 1,850,000 tons of frac sand per year. Assuming production at the rated capacity and based on a reserve report prepared by John T. Boyd, our Wyeville facility has an implied reserve life of 39 years as of December 31, 2018. In July 2018, the Partnership announced its plans to expand the production capacity at its Wyeville facility by an additional 850,000 tons per year. Following the expansion, the Wyeville facility’s annual processing capacity will increase to 2,700,000 tons of frac sand per year. The expansion at the Wyeville facility is expected to be complete in the first quarter of 2019.

All of the product from the Wyeville facility is shipped by rail from approximately 32,000 feet of track that connects our facility to a Union Pacific Railroad mainline. These rail spurs and the capacity of the associated product storage silos allow us to accommodate a large number of rail cars, including unit trains.

Augusta Facility

We own and operate a 1,187-acre facility with integrated rail infrastructure, located in Eau Claire County, Wisconsin (the "Augusta facility"), which, as of December 31, 2018, contained 42.1 million tons of proven recoverable reserves of frac sand meeting API specifications. Construction of the Augusta facility was completed in June 2012 and we expanded the facility in 2014. The Augusta facility has an annual processing capacity of approximately 2,860,000 tons of frac sand per year. Assuming production at the rated capacity and based on a reserve report prepared by John T. Boyd, our Augusta facility has an implied reserve life of 15 years as of December 31, 2018. The Augusta facility was temporarily idled in October 2015 until production resumed at reduced capacity levels in September 2016. The Augusta facility was again temporarily idled in January 2019.

All of the product from the Augusta facility is shipped by rail from approximately 38,000 feet of track that connects our facility to a Union Pacific Railroad mainline. These rail spurs and the capacity of the associated product storage silos allow us to accommodate a large number of rail cars, including unit trains.

Blair Facility

We own and operate a 1,285-acre facility with integrated rail infrastructure, located in Blair, Wisconsin (the "Blair facility"), which, as of December 31, 2018, contained 112.2 million tons of proven recoverable reserves of frac sand meeting API specifications. Construction of the Blair facility was completed in March 2016. The Blair facility has an annual processing capacity of approximately 2,860,000 tons of frac sand per year. Assuming production at the rated capacity and based on a reserve report prepared by John T. Boyd, our Blair facility has an implied reserve life of 39 years as of December 31, 2018.

All of the product from the Blair facility is shipped by rail from approximately 45,000 feet of track that connects our facility to a Canadian National Railway mainline. These rail spurs and the capacity of the associated product storage silos allow us to accommodate a large number of rail cars, including unit trains.

Whitehall Facility

We own and operate a 1,626-acre facility with integrated rail infrastructure, located in Independence, Wisconsin and Whitehall, Wisconsin (the "Whitehall facility"), which, as of December 31, 2018, contained 85.2 million tons of proven recoverable reserves of frac sand meeting API specifications. The Whitehall facility, completed in September 2014, has an annual processing capacity of approximately 2,860,000 tons of frac sand per year. Assuming production at the rated capacity and based on a reserve report prepared by John T. Boyd, the Whitehall facility has an implied reserve life of 30 years as of December 31, 2018. The Whitehall facility was temporarily idled during the second quarter of 2016 and resumed production in March 2017. In September 2018, the Partnership temporarily idled dry plant operations at the Whitehall facility and resumed production in January 2019.

All of the product from the Whitehall facility is shipped by rail from approximately 38,000 feet of track that connects the facility to a Canadian National Railway mainline. These rail spurs and the capacity of the associated product storage silos allow us to accommodate a large number of rail cars, including unit trains.

Kermit Facilities

In March 2017, we acquired a 1,226-acre frac sand reserve, located near Kermit, Texas, strategically positioned in the Permian Basin, within 75 miles of significant Delaware and Midland Basin activity. On July 31, 2017, we completed construction of our fifth on-site processing plant capable of producing 3,000,000 tons per year (the "Kermit facility") and commenced operations.

In December 2018, we completed construction of a second production facility, located on our reserves near Kermit, Texas ("Kermit 2 facility"), adding 3,000,000 tons per year of processing capacity. The Kermit 2 facility is located west of the existing Kermit facility with separate road access to enable efficient entrance and egress.

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The Kermit facilities, as of December 31, 2018, contained 100.0 million tons of proven recoverable reserves of frac sand meeting API specifications. Assuming production at the rated capacity and based on a reserve report prepared by John T. Boyd, the Kermit facilities have an implied reserve life of 17 years as of December 31, 2018.

All of the product from our Kermit facilities is delivered by truck to the wellsite from 12 on-site silos with 36,000 tons of storage capacity.

Terminal Facilities

As of December 31, 2018, we own or operate 12 terminal locations throughout Pennsylvania, Ohio, Texas, Colorado and New York, of which three are idled and seven are capable of accommodating unit trains. Our terminals include approximately 114,000 tons of rail storage capacity and approximately 140,000 tons of silo storage capacity. Each terminal location is strategically positioned in the shale plays to facilitate efficient delivery of sand to the wellsite. Our terminals include rail-to-storage and rail-to-truck capabilities and serve as the majority of our terminal resources and materials management services. Our terminal facilities include origin and distribution material staging areas, rail track capabilities, material handling equipment, private rail fleet, bulk storage and quality assurance services.

Our terminals are strategically located to provide access to Class I railroads, which enables us to cost effectively ship product from our Wisconsin production facilities. As of December 31, 2018, we leased or owned 4,986 railcars used to transport sand from origin to destination and managed a fleet of approximately 2,169 additional railcars dedicated to our facilities by our customers or the Class I railroads.

PropStream Operations

In September 2016, the Partnership entered into an agreement to become a member of Proppant Express Investments, LLC ("PropX"), which was established to develop critical last mile logistics equipment for the proppant industry. In October 2016, the Partnership began providing to customers its PropStream integrated logistics service, utilizing containers.

On August 1, 2018, the Partnership completed the acquisition of FB Industries, a company engaged in the engineering, design and marketing of silo-based frac sand management systems.

Our PropStream last mile solution utilizes container and/or silo systems, and maintains strict proppant quality control from the mine to the blender, while also addressing environmental concerns through reduction of particulate matter emissions. We handle the full spectrum of logistics management with the industry’s only fully integrated solution, from railcar fleet management to truck dispatching and dedicated wellsite operations, which structurally reduces costs for customers by eliminating inefficiencies throughout the proppant delivery process. PropStream helps eliminate supply risk, provides increased transportation efficiency and reduces supply chain related congestion at the wellsite, decreasing the number of trucks required per job and decreasing or eliminating trucking demurrage costs. Our PropStream integrated logistics service is designed to meet or exceed the new respirable crystalline silica standards adopted under the federal Occupational Safety and Health Act ("OSH Act") that became effective in June 2018 with respect to hydraulic fracturing, as well as the engineering control obligations to limit exposures to respirable crystalline silica that are set to become effective in June 2021 for hydraulic fracturing.

Competitive Strengths

We believe that we are well positioned to successfully execute our Mine. Move. Manage. operational strategy and achieve our primary business objectives to provide capital appreciation and increase our return to unitholders over time because of the following competitive strengths:

• Differentiated frac sand supply and logistics service. We provide integrated, mine-to-wellsite frac sand supply and logistics services to customers with an emphasis on safety, surety and efficiency. By controlling all points along the supply chain, we are able to better control quality and consistency of product, reduce delivery costs to our customers, and realize supply chain efficiencies, resulting in more efficient and productive wellsite operations for our customers. Our offerings are unique in their ability to provide customers with wellsite-specific solutions for proppant supply, delivery and management due to our control of Wisconsin and West Texas production facilities, multiple in-basin rail terminals, and both container and silo-based last mile and wellsite management solutions. This enables us to completely replace customers’ fragmented sand supply chains with a simplified infrastructure for purchasing and administration utilizing constantly adapting technologies and best practices, including jobsite and operational safety.

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• Long-term customer relationships. In conjunction with, and fully-supportive of, our integrated and differentiated frac sand and logistics service offering, we have developed and continue to expand our relationships with customers, particularly exploration and production companies ("E&Ps"). During the fourth quarter of 2018, 51% of our total sales volumes were to E&Ps, compared to having no sales direct to E&Ps at the start of 2017. These E&P relationships are built and strengthened through realization of mutual benefits that accrue to both us and our customers. These include more integrated near- and long-term supply/demand planning, lower volatility in sand and services demand, better visibility for us and our customers, surety of supply for our customers, surety of demand for our products and services, and greater emphasis on long-term cost savings versus near-term price fluctuations. These relationships are also supported by long-term contractual agreements. As of January 1, 2019, our long-term contracts have an average remaining contractual term of 2.3 years. Our contracts define, among other commitments, the volume of product that the Partnership must provide and the volume that the customer must purchase by the end of the defined periods. Pricing structures under our agreements are in many cases subject to certain contractual adjustments and consist of a combination of negotiated pricing and fixed pricing. A substantial portion of our logistics services are provided to customers with whom we have long-term agreements as defined in master services agreements ("MSA") and related work orders.  The MSA and related work orders are typically separate from any sand supply contract we may have with the same customer. We expect to continue selling a majority of our sand and services to our customers with long-term contracts in 2019 and future years. We believe the fully integrated service model combining sand and last mile logistics creates lasting relationships with our customers who value reliability of supply and cost effective delivery to the wellsite.

• Competitive operating cost structure. Our plant operations have been strategically designed to provide low per-unit production costs. At our Kermit facilities, our production costs benefit from a reserve base that is easily accessible with limited to no overburden and no royalty. Our Kermit facilities, located in the heart of the Permian Basin, are capable of loading produced frac sand directly into the truck and are logistically advantaged with proximity to significant frac sand demand and wellsite locations. At our Wisconsin facilities, we benefit from shallow overburden, which provides for a lower cost structure than mining operations of reserves with deeper or more complex overburden. We also benefit by having purpose-built facilities with similar designs, allowing for economics of scale in purchasing and labor flexibility. Our mining operations are subcontracted to a third-party excavation company at a fixed cost per ton excavated, subject to a diesel fuel surcharge. The strategic location and logistics capabilities of our portfolio of production facilities enables us to serve all major U.S. and Canadian oil and natural gas producing basins. Unlike many competitors, our processing and rail loading facilities are located on-site, which eliminates the requirement for on-road transportation, lowers product movement costs, minimizes degradation of sand quality due to handling at the origin and lowers environmental impact. Owning and operating our terminal network provides for reduced operating and freight costs, while also ensuring our customers receive priority scheduling, expedited delivery and a more cost-effective delivery alternative. Our fully integrated PropStream last mile solution utilizes purpose built equipment, minimizing operating costs as the wellsite.

• Strategically located terminal facilities. We deliver our frac sand through an extensive logistics network of owned and operated rail-based terminals strategically located throughout Pennsylvania, Ohio, Texas, Colorado and New York to serve our customers' operations in North America's shale and other unconventional oil and natural gas plays. Additionally, we have access to facilities owned and operated by third parties to further increase the reach of our logistics footprint and number of origin and destination pairings. Our distribution network allows us to better, and cost effectively, service our customers’ short-notice needs across basins, and provide our customers with reliable supply and solutions for the logistical challenges presented by the large volume of frac sand typically required for each well completion.

• Experienced and incentivized management team. Our management team has extensive experience operating in the oil and natural gas industry, long-term relationships with participants in the exploration and production and oilfield services industries, a strong operational and commercial understanding of the markets in which our customers operate, and expertise in development, construction and operation of frac sand processing and terminal facilities, bulk solids material handling, frac sand supply chain management, and rail and truck logistics. Our management team is focused on optimizing our current business and expanding our operations through disciplined execution of our Mine. Move. Manage. operational strategy. Our management team is well-aligned with the interests of common unitholders through their combined 5% direct ownership interest in our limited partnership units, whose value are directly impacted by prudent growth in profitability, cash flows and the overall success of the business.

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Business Strategies

Our primary business objectives are to provide capital appreciation and increase our return to unitholders over time. We intend to accomplish this objective by executing the following strategies:

• Providing sand as a service. As we meet our customers' varied and evolving needs, we focus on the management of frac sand for our customers through "sand as a service." Through the development and deployment of PropStream, our fully integrated last mile solution for delivery of sand using both containers and silo systems, we leverage our capabilities to manage our customers' frac sand and logistics needs all the way from the mine to the blender at the wellsite. Our relentless focus on execution of our operations aligns our service with their needs for quality and reliability as we handle the frac sand production, transportation and management challenges faced every day, while also placing a priority on safety.

• Focusing on long-term relationships with key customers. A key component of our business model is our integrated service model of providing sand and last mile services directly to the end user, particularly the larger E&Ps. Another component has been our sales strategy, which seeks to secure a high percentage of our volumes under long-term contracts with oil and natural gas E&Ps and major pressure pumping service providers. As of January 1, 2019, more than 60% of our currently operating production capacity is under long-term contracts with E&Ps and during the fourth quarter of 2018, 51% of our total sales volumes were to E&Ps. We believe this provides a more stable base of cash flow, while also providing the flexibility we and our customers desire in the event of market changes. We believe this business model serves as the foundation for our ability to serve our customers, while reliably providing the product that is a critical component to the well completion process. We intend to utilize a substantial majority of our processing capacity to fulfill our customer contracts and continue to serve our existing and new customers with frac sand delivered through our distribution network and to the blender at the wellsite. We also intend to expand our PropStream services provided to our long-term relationships to further optimize their sand supply chain and reduce their cost of well completions.

• Capitalizing on compelling industry fundamentals. We intend to continue positioning ourselves as a premier provider of proppant and logistics solutions to the North American energy industry, as we believe the proppant and logistics market offers attractive growth fundamentals over the long-term. The innovations in horizontal drilling in the various North American shale basins and other unconventional oil and natural gas plays have resulted in greater demand for frac sand per well and per stage. The long-term growth in frac sand demand and related logistics services is underpinned by continued horizontal drilling, increasing frac sand use per well and cost advantages over other proppant types, including resin-coated sand and ceramics.

• Building on our position as a low cost provider. We seek to maintain and improve upon our position as a low cost provider of frac sand. We will continue to analyze and pursue organic expansion efforts that will similarly allow us to capitalize on and cost-effectively optimize our existing production and logistics assets. For example, in 2018 we developed the second Kermit facility and began expansion of the Wyeville facility supported by a sand supply agreement with a major operator in the Permian. In addition, we seek to identify and evaluate additional terminal site locations to expand our geographic footprint allowing us to enhance our distribution network and ensure that our frac sand production is available to meet the evolving and dynamic in-basin needs of our customers. Further, we seek to find ways to reduce our customers' cost of frac sand delivered to the blender at the wellsite regardless of the source of production. We intend to accomplish this through a combination of our low cost production, our network of owned and operated terminals or third-party operated sites, our geographic footprint, and our PropStream integrated logistics service. We intend to continue to analyze and pursue opportunities to cost-effectively expand our geographic reach, optimize our existing assets and meet our customers' demand for our high quality frac sand.

• Pursuing accretive acquisitions. In June 2013, we acquired D&I Silica, LLC ("D&I"), the owner of the largest distribution network in the Marcellus and Utica shale plays. The foundation of this acquisition enabled us to operate through an extensive logistics network of rail-based terminals, which today, has been expanded and is strategically located throughout Pennsylvania, Ohio, Texas, Colorado and New York. In separate transactions between 2013 and 2017, we acquired all of the equity interests in the Augusta, Blair and Whitehall facilities previously owned by our sponsor. In March 2017, we acquired a 1,226-acre frac sand reserve, located near Kermit, Texas from Permian Basin Sand Company, LLC. In August 2018, we acquired FB Industries, a company engaged in the engineering, design and marketing of silo-based frac sand management systems. We expect to continue pursuing accretive acquisitions of third-party frac sand assets, including production facilities and/or distribution and logistics operations. As we evaluate acquisition opportunities, we intend to remain focused on operations that complement our reserves of premium frac sand, our portfolio of efficient production facilities, and assets that provide or would accommodate the development and construction of advantaged logistics and distribution capabilities. We believe these factors are critical to our business model and are important characteristics for any potential acquisitions.

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• Maintaining financial flexibility and ample liquidity. We continue to pursue a disciplined financial policy and maintain liquidity aligned with our future financing needs and debt maturities. As of February 14, 2019, we had cash of $61.5 million and our senior secured revolving credit facility (the "ABL Credit Facility") had $58.7 million pursuant to available borrowings ($79.8 million, net of $21.1 million letter of credit commitments), resulting in total liquidity of $120.2 million. The ABL Credit Facility is available to fund working capital and general corporate purposes, including the making of certain restricted payments permitted therein. Borrowings under our ABL Credit Facility are secured by substantially all of our assets. On August 1, 2018, the Partnership completed the private placement of $450.0 million aggregate principal amount of its 9.50% senior unsecured notes due 2026 (the "Senior Notes"). In January 2017, we entered into an equity distribution program under which we may sell through or to certain financial institutions up to $50.0 million in common units. In addition, in 2016 and 2017, we completed four public offerings of a total of 43,125,000 common units for aggregate net proceeds of $601.6 million. We believe that our borrowing capacity and ability to access debt and equity capital markets provides us with the financial flexibility necessary to achieve our organic expansion and acquisition strategy.

• Corporate Conversion. The board of directors of the general partner unanimously approved the Plan of Conversion. The Partnership filed a preliminary proxy statement with the SEC on February 5, 2019. The proxy statement relates to a special meeting of unitholders that is expected to be held on April 11, 2019 and at which unitholders will be asked to consider and vote upon proposals relating to the Conversion, which, subject to unitholder approval, will be completed through a series of transactions set forth in the Plan of Conversion.  As a result of the Conversion, the Partnership will convert from an entity treated as a partnership for U.S. federal income tax purposes to an entity treated as a corporation for U.S. federal income tax purposes.  We believe the Conversion is critical to the future success of the Partnership. With the reduction in the number of master limited partnerships generally and the increased focus of the Partnership’s business on logistics, we believe that accomplishing our growth plans and executing on our strategy for long-term success are best achieved through a traditional corporate structure. We also believe that the transition to a C-Corporation will streamline corporate governance benefiting shareholders with enhanced protections and rights. In addition, we believe the Conversion will increase our access to, and lower the cost of, capital by increasing trading liquidity and making us more accessible to a broader investor base. Subject to receipt of unitholder approval, the Partnership currently expects to complete the Conversion shortly following conclusion of the special meeting. Upon completion of the Conversion, we expect to be renamed "Hi-Crush Inc." and our common stock will be listed for trade on the New York Stock Exchange ("NYSE") under the ticker symbol "HCR."

Our Industry

The oil and natural gas proppant industry is comprised of businesses involved in the mining, manufacturing and delivery of the propping agents used in the completion of oil and natural gas wells. Hydraulic fracturing is the most widely used method for stimulating increased production from wells. The process consists of pumping fluids, mixed with granular proppants, into the geologic formation at pressures sufficient to create fractures in the hydrocarbon-bearing rock. Proppant-filled fractures create conductive channels through which the hydrocarbons can flow more freely from the formation into the wellbore and then to the surface.

Industry Data

The market and industry data included throughout this Annual Report on Form 10-K was obtained through our own internal analysis and research, coupled with industry publications, surveys, reports and other analysis conducted by third parties. Industry publications, surveys, reports and other analysis generally state that the information contained therein has been obtained from sources believed to be reliable, although they do not guarantee the accuracy or completeness of such information. Although we believe that the industry reports are generally reliable, we have not independently verified the industry data from third-party sources. Although we believe our internal analysis and research is reliable and appropriate, such internal analysis and research has not been verified by any independent source.

Types of Proppant

There are three primary types of proppant that are commonly utilized in the hydraulic fracturing process: raw frac sand, resin-coated sand and manufactured ceramic beads. We are engaged exclusively in the production of raw frac sand.

Raw Frac Sand

Of the three primary types of proppant, raw frac sand is the most widely used due to its broad applicability in oil and natural gas wells and its cost advantage relative to other proppants. Raw frac sand has been employed in nearly all major U.S. oil and natural gas producing basins.

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Raw frac sand is generally mined from the surface or underground, and in some cases crushed, and then cleaned, dried and sorted into consistent mesh sizes. The API has a range of guidelines it uses to evaluate frac sand grades and mesh sizes. In order to meet API specifications, frac sand must meet certain thresholds related to crush strength (ability to withstand high pressures), roundness and sphericity (facilitates hydrocarbon flow, or conductivity), particle size distribution, turbidity (low levels of contaminants), acid solubility and percent quartz (mineralogy). Oil and natural gas producers generally require that frac sand used in their drilling and completion processes meet API specifications.

Raw frac sand can be further delineated into three main types: Northern White, Brady Brown and what is commonly referred to as "In-Basin" frac sand. The term "Northern White" is a commonly-used designation for premium white sand produced in Wisconsin and other limited parts of the upper Midwest region of the United States. Northern White, which is the type of frac sand we produce at our Wisconsin facilities, is known for its high crush strength, low turbidity, roundness and sphericity and monocrystalline grain structure. Northern White frac sand has historically commanded premium prices relative to Brady Brown. Brady Brown, or regional sand, had been preferred due to its proximity the Permian Basin and Eagle Ford shale plays, and, therefore, its lower cost due to reduced logistics costs compared to Northern White frac sand. In-Basin frac sand began to be developed and produced in 2017 in the Permian Basin and is also being developed and produced in the Eagle Ford, Haynesville and Mid-Con basins and has been adopted quickly due to its proximity to wellsites and reduced logistics costs. We produce Northern White and In-Basin frac sand at our production facilities.

Resin-Coated Frac Sand

Resin-coated frac sand consists of raw frac sand that is coated with a flexible resin that increases the sand’s crush strength and prevents crushed sand from dispersing throughout the fracture. Precured (or tempered) resin-coated sand primarily enhances crush strength, thermal stability and chemical resistance, allowing the sand to perform under harsh downhole conditions. Curable (or bonding) resin-coated frac sand uses a resin that is designed to bond together under closure stress and high temperatures, preventing proppant flowback. We do not produce resin-coated frac sand, but from time to time, we may purchase or transload resin-coated frac sand for use by our customers.

Ceramics

Ceramic proppant is a manufactured product of comparatively consistent size and spherical shape that typically offers the highest crush strength relative to other types of proppants. Ceramic proppant derives its product strength from the molecular structure of its underlying raw material and is designed to withstand extreme heat, depth and pressure environments. We do not produce ceramic proppant, but from time to time, we may purchase or transload ceramic proppant for use by our customers.

Proppant Mesh Sizes

Mesh size is used to describe the size of the proppant and is determined by sieving the proppant through screens with uniform openings corresponding to the desired size of the proppant. Each type of proppant comes in various sizes, categorized as mesh sizes, and the various mesh sizes are used in different applications in the oil and natural gas industry. The mesh number system is a measure of the number of equally sized openings per square inch of screen through which the proppant is sieved. For example, a 40 mesh screen has 40 equally sized openings per linear inch. Therefore, as the mesh number increases, the granule size decreases. In order to meet API specifications, 90% of the proppant described as 40/70 mesh size proppant must consist of granules that will pass through a 40 mesh screen but not through a 70 mesh screen. We excavate various mesh sizes at our facilities, and sell 20/40, 30/50, 40/70 and 100 mesh frac sand used in the hydraulic fracturing process.

Demand Trends

Demand for frac sand and other proppants is primarily driven by oil and natural gas drilling and well completion technology and techniques, such as horizontal drilling and hydraulic fracturing, as well as overall industry activity. We believe that demand for proppant will grow over the long-term as a result of the following demand drivers:

• improvements in drilling rig productivity (from, among other things, pad drilling), resulting in more wells drilled per horizontal rig per year;

• increases in the number of wells drilled per acre;

• increases in the length of the typical horizontal wellbore;

• increases in the number of fracture stages per lateral foot in the typical completed horizontal wellbore;

• increases in the volume of proppant used per fracturing stage; and

• recurring efforts to offset steep production declines in unconventional oil and natural gas reservoirs, including the drilling of new wells and secondary hydraulic fracturing of existing wells.

Demand fundamentals are expected to improve in 2019 compared to the latter part of 2018, particularly as some of the factors limiting demand in the back half of 2018, including E&P budget exhaustion and pipeline take-away constraints, are alleviated.

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Additionally, an increase in the number of drilled but uncompleted wells represents pent up demand for completion services and frac sand that will provide further support for overall demand in 2019 and beyond, regardless of rig count activity.

Demand for logistics services associated with frac sand has been directly correlated with the demand for frac sand, and is expected to grow in the second half of 2019 supported by the frac sand demand fundamentals.

Supply Trends

In response to growing demand for U.S. frac sand, the industry has developed additional capacity, with the majority of this development in the Permian Basin. In 2017, several new and existing suppliers announced planned capacity additions of frac sand supply. With the completion of construction and start-up of operations at several Permian Basin mines during 2018 as well as mines in the Eagle Ford and other basins, In-Basin supply is becoming more available. Frac sand supply currently exceeds demand, however, we believe the supply and demand will be in balance over time as demand continues to grow over the coming years. While stated frac sand capacity may exceed near-term demand, available industry capacity is constrained due to several factors, including availability of the grades of frac sand that are most in demand in certain regions or well completion environments, general operating conditions and normal downtime, and logistics constraints.

The advent of In-Basin sand supply available closer to the wellsite in the Permian Basin, and to a lesser extent in the Eagle Ford, Haynesville and Mid-Con basins, has resulted in a rapid shift in supply from Northern White sand to In-Basin sand supply. However, we believe this shift is specific to finer mesh sizes of sand, particularly 100 mesh which is the principal grade produced in-basin. Northern White supply of 100 mesh is likely to shift to meet the demand for sand in other basins, with other mesh sizes of Northern White continuing to find a market in the Permian Basin. While these shifts may cause periodic mismatches of supply and demand in particular basins, we do not believe there will be a long-term oversupply of sand given the projections of increasing demand.

The onset of reduced completion activity beginning in the third quarter of 2018 has caused frac sand demand growth to lag the increase in supply, and has resulted in a significant reduction in pricing, particularly for Northern White sand, that is impacting sand pricing in all basins. These factors have resulted in declines in pricing of 10 percent or more in the latter part of 2018. In response to the price decline, we and many of our competitors have reduced available capacity through the temporary idling of facilities. In September 2018, the Partnership temporarily idled dry plant operations at the Whitehall facility and resumed production in January 2019. Our Augusta facility was temporarily idled in January 2019.

We believe there will be continued demand for Northern White frac sand within the Permian Basin as completions activity within that basin increases due to customer preferences and other factors. However, we believe a large portion of Northern White frac sand which previously supplied the Permian Basin was displaced in 2018 due to continued adoption of locally-produced sand. These Northern White volumes are being reallocated into other major oil and natural gas basins around the country where they are most cost-effectively delivered via rail, barge or other modes of transportation, and which do not have the same readily available production of In-Basin sand. However, over time we believe frac sand facilities producing Northern White at a higher cost are likely to be idled or permanently shut down due to increased competition within these regions resulting in realized sales pricing below the level at which such facilities can profitably operate. At this time it is not possible to determine which facilities will be idled or shut down, or the exact timeframe in which such actions would be taken.

There are several potential geological, operational and economic constraints to increasing raw frac sand production on an industry-wide basis, including:

• the difficulty of finding frac sand reserves that meet API specifications and consisting of the mesh size in demand;

• the difficulty of securing contiguous frac sand reserves large enough to justify the capital investment required to develop a processing facility with a higher base of fixed costs;

• the challenges of identifying frac sand reserves with the above characteristics that either are located in close proximity to oil and natural gas reservoirs or have rail access needed for low-cost transportation to major shale basins;

• the hurdles of securing mining, production, water, air, refuse and other federal, state and local operating permits from the proper authorities;

• local opposition to development of facilities, especially those that require the use of on-road transportation, including hours of operations and noise level restrictions, in addition to moratoria on raw frac sand facilities in some jurisdictions in Wisconsin and other states which hold potential sand reserves; and

• the typically long lead time required to design and construct sand processing facilities that can efficiently process large quantities of high quality frac sand.

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Logistics services are provided in various combinations of service components including railcar fleet management, truck dispatching and dedicated wellsite operation.  Supply of last mile logistics services broadly fall in the categories of transitional pneumatic trucking operations, container solutions and silo systems.  There are a number of small and large competitors in the three broad categories with new technologies being developed and tested.  We believe a differentiating factor among the various competitors will be the reliability of the service and the execution on a day-to-day basis and, over time, we expect consolidation of the service offerings in the industry.

Pricing

Given the expectation for increased oil and natural gas exploration and production activity in North America, coupled with the increased proppant demand per well, and the increases in sand supply noted above, frac sand pricing has been volatile, rising from the latter half of 2016 through the first half of 2018. During the latter half of 2018, frac sand pricing reversed trend and rapidly declined due to the combined impact of increasing supplies of In-Basin sand and reduced completions activity. We believe pricing could improve during 2019 as new supply is expected to be absorbed by the potential increase in demand as disadvantaged supply is idled.

There are numerous grades and sizes of proppant which sell at various prices, dependent primarily upon the delivery point, and also quality, grade of proppant, deliverability and many other factors.  Pricing of proppant sold at the terminal is higher than pricing of proppant sold FOB plant as a result of the associated transportation and handling costs to bring the sand from the mine to the terminal. No reliable publicized pricing information for raw sand exists. However, it is believed that the overall pricing trends tend to be consistent across the various sizes and within regions with some variation due to transportation costs, resulting from distance from the source.  We believe a significant amount of proppant is sold under long-term contracts with varying pricing mechanisms, with the remainder being sold under short-term pricing arrangements.

Pricing for logistics services is generally based on a fixed component for labor and equipment and a variable component based on transportation costs.  Pricing for logistics services has been less volatile than frac sand pricing over the past few years, but is becoming more competitive given the increasing number of companies and technologies offering certain services or combinations thereof. 

Customers and Contracts

Our current customer base includes major oil and natural gas exploration and production companies and pressure pumping service providers. For the year ended December 31, 2018, sales to Chevron USA Inc. ("Chevron") and Halliburton Company ("Halliburton") each accounted for greater than 10% of our total revenues. For the year ended December 31, 2017, sales to each of Halliburton and Liberty Oilfield Services ("Liberty") accounted for greater than 10% of our total revenues. For the year ended December 31, 2016, sales to each of Halliburton, Liberty, US Well Services, LLC and Weatherford International Ltd. accounted for greater than 10% of our total revenues.

A substantial portion of our frac sand is sold to customers with whom we have long-term contracts. For the year ended December 31, 2018, we generated 87% of our revenues from sales of frac sand to customers with whom we had long-term contracts. We expect to continue selling a majority of our sand to our customers with long-term contracts in 2019 and future years. As of January 1, 2019, our long-term contracts have an average remaining contractual term of 2.3 years with remaining terms ranging from 15 to 72 months.

Our contracts define, among other commitments, the volume of product that the Partnership must provide and the volume that the customer must purchase by the end of the defined periods. Pricing structures under our agreements are in many cases subject to certain contractual adjustments and consist of a combination of negotiated pricing and fixed pricing. These arrangements may undergo negotiations regarding pricing and volume requirements, which may occur in volatile market conditions. We also sell sand on the spot market, at prices and other terms determined by the existing market conditions as well as the specific requirements of the customer.

A substantial portion of our logistics services are provided to customers with whom we have long-term agreements as defined in master services agreements ("MSA") and related work orders.  The MSA typically outlines the general terms and conditions for work performed by us relating to invoicing, insurance, indemnity, taxes and similar terms.  The work orders typically define the commercial terms including the type of equipment and services to be provided, with pricing that is generally determined on a job-by-job basis due the variability in the specific requirements of each wellsite.  The MSA and related work orders are typically separate from any sand supply contract we may have with the same customer.

We may, from time to time, sell silo systems and related equipment to third parties at negotiated prices for the specific equipment.

Suppliers

Although the majority of the frac sand that we sell is produced from our production facilities, we can purchase, and have purchased in the past, a certain amount of frac sand and other proppant from various third parties for sale to our customers. During the years ended December 31, 2018 and 2017, the Partnership purchased 267,628 and 142,019 tons, respectively, from third parties. During the year ended December 31, 2016, the Partnership did not purchase any sand from third parties. 

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Our Operations

Frac Sand Excavation Operations

Raw frac sand is a naturally occurring mineral that is mined and processed. While the specific extraction method utilized depends primarily on the geologic setting, most raw frac sand is mined using conventional open-pit bench extraction methods. The composition, depth and chemical purity of the sand also dictate the processing method and equipment utilized. For example, broken rock from a sandstone deposit may require one, two or three stages of crushing to produce sand grains required to meet API specifications. In contrast, unconsolidated deposits (loosely bound sediments of sand), like those found at our Wyeville facility, may require little or no crushing during the excavation process.

The surface excavation operations at our production facilities are conducted by a third-party contractor. The mining technique at our production facilities is open-pit excavation of approximately 20-acre panels of unconsolidated silica deposits. At our Kermit facilities, unconsolidated dune sand is mined through the excavation process. At our Augusta, Blair and Whitehall facilities, the excavation process involves clearing vegetation and trees overlying the proposed mining area. Additionally, limited blasting procedures are conducted at our Augusta, Blair and Whitehall facilities. The initial two to five feet of overburden is removed and utilized to construct perimeter berms around the pit and property boundary. No underground mines are operated at our production facilities.

A track excavator and articulated trucks are utilized for excavating the sand at several different elevation levels of the active pit. The pit is dry mined, and if necessary, the water elevation is maintained below working level through a dewatering and pumping process. The mined material is loaded and hauled from different areas of the pit and different elevations within the pit to the primary loading facility at our mines' on-site wet processing facilities. We pay a fixed fee per ton of sand excavated, subject to a diesel fuel surcharge.

At our Wyeville facility, in addition to surface excavation, sand is also mined through dredging operations.  Silica deposits are extracted from the ground with water.  The resulting slurry is transported via pipeline to the wet processing facility.  Similar to surface excavation operations, the dredging at our Wyeville facility is performed by a third-party contractor.

Processing Facilities

Our processing facilities are designed to wash, sort, dry and store our raw frac sand, with each plant employing modern and efficient wet and dry processing technology.

Our mined raw frac sand is initially stockpiled before processing. The material is recovered by a mounted belt feeder, which extends beneath a surge pile and is fed onto a conveyor. The sand exits the tunnel on the conveyor belt and is fed into the wet plant where impurities, such as clay and organic particles, and unusable fine grain sand are removed from the raw feed. The wet processed sand is then stockpiled in advance of being fed into the dry plant for further processing. The Wisconsin wet plants operate for seven to eight months per year due to the limitations arising from sustained freezing temperatures during winter months. When in operation, our Wisconsin wet plants process more sand per day than the dry plants can process to build up stockpiles of frac sand that will be processed by the dry plants during the winter months. The Kermit wet plants operate year round and therefore the stockpiles of frac sand are processed by the dry plants in a shorter timeframe.

The wet processed sand stockpile is fed into the dry plant hopper using a front end loader. The material is processed in a natural gas fired vibratory fluid bed dryer contained in an enclosed building. After drying, the sand is screened through gyratory screens and separated into industry standard product sizes. The finished product is then conveyed to multiple on-site storage silos for each size specification and our railcar loads are tested to ensure that the delivery meets API specifications. Oil and natural gas producers increasingly require current testing and proof that frac sand used in their drilling and completion processes meet API specifications.

Logistics Capabilities

Most frac sand is shipped in bulk from the processing facility to terminal facilities, or directly to the customers by truck, rail or barge. For bulk raw frac sand, transportation costs often represent a significant portion of the customer’s overall product cost. Consequently, shipping in large quantities, particularly by unit train when shipping over long distances, provides a significant cost advantage to the customer, emphasizing the importance of rail or barge access for low cost delivery. As a result, facility location and logistics capabilities are among the most important considerations for producers, distributors and customers.

All of the product sold from our Wyeville and Augusta facilities is shipped by rail from approximately 32,000 feet and 38,000 feet, respectively, of track that connects our facilities to a Union Pacific Railroad mainline. All of the product sold from our Blair and Whitehall facilities is shipped by rail from approximately 45,000 feet and 38,000 feet, respectively, of track that connects our facility to a Canadian National Railway mainline. These rail spurs, size of the rail yards and the capacity of the associated product storage silos allow us to accommodate a large number of rail cars, including unit trains, which significantly increases our efficiency in meeting our customers’ frac sand transportation needs. All of the product sold from our Kermit facilities is delivered by truck to the wellsite from 12 on-site silos with 36,000 tons of storage capacity.

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Terminal Operations

We generally operate our terminal locations under long-term lease agreements with third-party operators or short-line rail companies. Some of these lease agreements include performance requirements, which typically specify a minimum number of rail cars that must be processed by us each year through the terminal. Each owned or operated terminal location is strategically positioned in the shale plays so that our customers typically do not need to travel more than 75 miles from the wellsite to purchase their frac sand requirements. Our terminals include rail-to-truck and, at silo storage locations, rail-to-storage capabilities.

Once the frac sand is loaded into rail cars at the origin, we utilize an extensive network through a combination of Class I and short-line railroads to move the sand to our terminals. For our terminals with silo storage capabilities, frac sand is loaded into delivery trucks directly from our silos. Our silos deploy sand via gravity to trucks stationed directly on scales under each silo with the loading, electronic recording of weight and dispatch of the truck capable of being completed in less than five minutes. Silos are considerably more efficient than conveyors, which require trucks to be loaded and then moved to separate scales to be weighed; however, frac sand can also be unloaded to delivery trucks directly via a conveyor.

PropStream Operations

Our PropStream last mile solution maintains strict proppant quality control from the mine to the blender, while also addressing environmental concerns through reduction of particulate matter emissions. We handle the full spectrum of logistics management, from railcar fleet management to truck dispatching and dedicated wellsite operation, structurally reducing costs for customers by eliminating inefficiencies throughout the proppant delivery process. PropStream provides increased transportation efficiency and reduces supply chain related congestion at the wellsite, decreasing the number of trucks required per job and decreasing or eliminating trucking demurrage costs. Our PropStream integrated logistics service is designed to meet or exceed the new OSH Act respirable crystalline silica standards with respect to hydraulic fracturing, as well as the engineering control obligations set to become effective in 2021 for hydraulic fracturing. PropStream helps eliminate supply risk and improve efficiency with the industry’s only fully integrated solution offering both container and silo systems.

Containers: Our PropStream container service involves loading proppant into containers before being transported by truck to the wellsite. The 8-foot cubic, purpose-built containers each transport up to 33,000 pounds of proppant and, depending on Department of Transportation and local regulations, allow for the transport of up to 55,000 pounds per truck.  The containers utilize intermodal container chassis or standard flatbeds for transportation, resulting in significant savings in terms of up-front and ongoing operations costs versus widely used pneumatic equipment. Each truck delivers up to 25 tons of proppant in two easily handled, small-footprint containers. Our PropStream container service also provides flexible and scalable storage at the wellsite compared to silo solutions and more precise delivery of proppant into the blender hopper. Individual, coded containers reduce the risk of product contamination and stranded product, and preserve proppant integrity and mix flexibility at the blender. On single-well locations and when pad access is difficult or limited, we believe PropStream containers are a compact, flexible logistic solution that optimize delivery and wellsite footprint.

At the wellsite, the PropBeast^® conveyor system significantly reduces noise and dust emissions due to its enclosed environment.  Gravity fed loading and unloading results in faster operations and greatly reduces proppant degradation. PropBeast conveyors can transfer approximately 60,000 pounds of proppant per minute into blender hoppers while reducing particulate matter emissions from sand operations at the wellsite by more than 90% versus the widely used pneumatic equipment alternative.

Silos: Our PropStream silos systems optimize the well pad with more proppant tons per square foot. The silos manage large sand quantities or high rates of pumping in a small footprint. A single 6-pack silo configuration increases wellsite storage more than 30% versus competitor silos. The customizable wellsite configurations meet most space requirements. With a variety of silo configurations and sizes, and crane-free hydraulic lift and transport, our silo systems provide maximum flexibility and improve safety. The PropStream silo system provides flexible, high capacity proppant delivery options using hopper bottom and pneumatic trailers. An innovative conveyor system, the FB Atlas, speeds unloading while a state-of-the-art telescopic discharge tube top-fills silos in significantly less the time of traditional pneumatic systems. We believe the silo systems are the ideal choice for multiwell operations and high proppant intensity well completions.

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Competition

There are numerous large and small producers in all sand producing regions of the United States with which we compete. Our main public and private competitors, including logistics only providers, include:

• Badger Mining Corporation

• Black Mountain Sand Holdings, LLC

• Covia Holdings Corporation (NYSE: CVIA)

• Emerge Energy Services LP (NYSE: EMES)

• Smart Sand, Inc. (NASDAQ: SND)

• Solaris Oilfield Infrastructure Inc (NYSE: SOI)

• U.S. Silica Holdings, Inc. (NYSE: SLCA)

• Vista Proppants and Logistics Inc.

The most important factors on which we compete are price, reliability of supply, transportation capabilities, product quality, performance and sand characteristics. Demand for frac sand and the prices that we will be able to obtain for our products are closely linked to proppant consumption patterns for the completion of oil and natural gas wells in North America. These consumption patterns are influenced by numerous factors, including the price for hydrocarbons, the drilling rig count and hydraulic fracturing activity, including the number of stages completed and the mesh size and amount of proppant used per stage. Further, these consumption patterns are also influenced by the location, quality, price and availability of proppant.

Our History and Relationship with Hi-Crush Proppants LLC

Overview and History

Hi-Crush Proppants LLC, our previous sponsor, was formed in 2010 in Houston, Texas by members of our management team and our general partner's board of directors. On October 21, 2018, the Partnership entered into a contribution agreement with our sponsor pursuant to which the Partnership acquired all of the then outstanding membership interests in the sponsor and the non-economic general partner interest in the Partnership. Upon completion of the acquisition, all of the outstanding incentive distribution rights representing limited partnership interests in the Partnership were canceled and extinguished and the sponsor waived any and all rights to receive contingent consideration payments from the Partnership or our subsidiaries pursuant to certain previously entered into contribution agreements to which it was a party.

Our Management and Employees

We are managed and operated by the board of directors and executive officers of our general partner, a wholly owned subsidiary of the Partnership. The general partner has the right to appoint all members of the board of directors of our general partner, including at least three independent directors meeting the independence standards established by the NYSE. Our unitholders are not entitled to elect directors or otherwise directly participate in our management or operations. Even if our unitholders are dissatisfied with the performance of our general partner, they have limited ability to remove the general partner. Our unitholders are able to indirectly participate in our management and operations only to the limited extent actions taken by our general partner require the approval of a percentage of our unitholders and our general partner and its affiliates do not own sufficient units to guarantee such approval.

As of December 31, 2018, the Partnership had 720 employees. In addition, we contract our excavation and trucking operations to third parties and accordingly have no employees directly involved in those operations.

Environmental and Occupational Safety and Health Regulation

Mining and Workplace Safety

Federal Regulation

Our frac sand mining operations are subject to the oversight of the U.S. Mine Safety and Health Administration ("MSHA"), which is the primary regulatory agency with jurisdiction over the commercial silica industry. MSHA regulates quarries, surface mines, underground mines, and the industrial mineral processing facilities associated with quarries and mines. The MSHA administers and enforces the provisions of the Federal Mine Safety and Health Act of 1977 ("MSH Act") to substantiate compliance with mandatory miner safety and health standards. As part of MSHA’s oversight, its representatives must perform at least two unannounced inspections annually for each surface mining facility in its jurisdiction. To date, these inspections have not resulted in any citations for material violations of MSHA standards at our mining facilities.

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We also are subject to the requirements of the OSH Act and comparable state statutes that regulate the protection of the health and safety of workers with federal oversight provided primarily by the U.S. Occupational Safety and Health Administration ("OSHA"). OSHA has adopted and implemented a Hazard Communication Standard that requires information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities, and the public. OSHA regulates the users of commercial silica and provides detailed regulations requiring employers to protect employees from overexposure to silica through the enforcement of permissible exposure limits and its Hazard Communication Standard. In 2016, OSHA published a final rule that established a more stringent permissible exposure limit for exposure to respirable crystalline silica and provided other provisions protective of employees involved in hydraulic fracturing activities including handling of frac sand. See Risk Factors under Item 1A of this Form 10-K for further discussion on mining safety and health standards, financial assurance requirements relating to reclamation and restoration of mining property; respirable crystalline silica-related regulatory standards and other legal requirements relating to miner protection.

Health and Safety Programs

We adhere to a strict occupational health program aimed at controlling employee exposure to silica dust, which includes a silicosis prevention program comprised of routine dust sampling, medical surveillance, training, and other components. Our safety program is designed to ensure compliance with MSHA and OSHA regulations. For health and safety standards, hazard and risk assessment tools and critical task specific awareness, extensive training is provided to employees. We have daily pre-task meetings and safety toolbox meetings at all our plants with personnel and conduct monthly focus fatality hazard prevention assessments as well as quarterly corporate health and safety compliance audits quarterly. Additionally, we perform annual internal health and safety system audits and conduct annual crisis management drills to test our abilities to respond to various situations. Health and safety programs are administered by our corporate health and safety department with the assistance of plant Environmental, Health and Safety Coordinators.

Environmental Matters

We and the commercial silica industry are subject to extensive governmental environmental laws and regulations governing, among other things, environmental permitting and licensing requirements, plant and wildlife protection, air emissions and water discharges, soil and groundwater contamination, waste management, hazardous materials, land use, remediation, reclamation and restoration of properties and natural resources. A variety of federal, state and local agencies implement and enforce these laws and regulations. See Risk Factors under Item 1A of this Form 10-K for further discussion on hydraulic fracturing; air emissions, including climate change and greenhouse gas ("GHG") emissions; water availability and discharges, plant and wildlife protection; and other legal requirements relating to environmental protection.

Federal Regulation

The Federal Water Pollution Control Act, also known as the Clean Water Act, and analogous state laws impose restrictions and strict controls on the discharge of pollutants, including spills and leaks of oil and other substances, into state waters or waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a Clean Water Act Section 402 permit issued by the U.S. Environmental Protection Agency ("EPA") or an analogous state agency to whom the EPA has delegated implementation of the permit program. With respect to our frac sand processing facilities in Wisconsin and Texas, those state agencies include the Wisconsin Department of Natural Resources ("WDNR") and the Texas Commission on Environmental Quality ("TCEQ"), respectively. Additionally, we may be obligated to obtain individual permits or coverage under general permits issued by the WDNR and TCEQ for stormwater runoff associated with construction activities. Also, we may be required to obtain permits under Section 404 of the Clean Water Act from the U.S. Army Corps of Engineers ("Corps") for the discharge of dredged or fill material into waters of the United States, including wetlands and streams, in connection with our operations. Failure to obtain these required permits or to comply with their terms could subject us to administrative, civil and criminal penalties as well as injunctive relief.

The federal Clean Air Act ("CAA") and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. These regulatory programs may require us to install expensive emissions abatement equipment, modify operational practices, and obtain permits for existing or new operations. Before commencing construction on a new or modified source of air emissions, such laws may require us to reduce emissions at existing facilities. As a result, we may be required to incur increased capital and operating costs to comply with these regulations. We could be subject to administrative, civil and criminal penalties as well as injunctive relief for noncompliance with air permits or other requirements of the CAA and comparable state laws and regulations. Furthermore, regulatory bodies at the federal, tribal, regional, state and local levels in the United States as well as internationally and certain non-governmental organizations have been increasingly focused on climate change issues including GHG emissions. The EPA has adopted regulations under authority of the existing CAA that impose reporting obligations with respect to GHG emissions, including methane and restrictions on various regulated entities including our E&P customers, which obligations and restrictions may increase our customers' costs of conducting operations and adversely affect demand for the oil and natural gas they produce, which could reduce demand for the fracturing sand that we mine, process and sell.

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As part of our operations, we utilize or store petroleum products and other substances such as diesel fuel, lubricating oils and hydraulic fluid. We are subject to regulatory programs pertaining to the storage, use, transportation and disposal of these substances. Spills or releases may occur in the course of our operations, and we could incur substantial costs and liabilities as a result of such spills or releases, including claims for injuries to persons or damages to natural resources and properties. The federal Comprehensive Environmental Response, Compensation, and Liability Act ("CERCLA"), also known as the Superfund law, and comparable state laws may impose joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of hazardous substances into the environment. These persons include the owner or operator of the site where the release occurred and anyone who disposed of or arranged for disposal, including offsite disposal, of a hazardous substance generated or released at the site. Under CERCLA, such persons may be subject to liability for the costs of cleaning up the hazardous substances, for damages to natural resources, and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

In addition, the federal Resource Conservation and Recovery Act ("RCRA") and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and clean-up of hazardous and non-hazardous wastes. The EPA, as well as the WDNR and TCEQ, to which the EPA has delegated portions of the RCRA program for local implementation, administer the RCRA program.

Our operations may also be subject to broad environmental review under the National Environmental Policy Act ("NEPA"). NEPA requires federal agencies to evaluate the environmental impact of all "major federal actions," which could include a major development project, such as a mining operation, significantly affecting the quality of the human environment. Therefore, our projects may require review and evaluation under NEPA. As part of this evaluation, the federal agency considers a broad array of environmental impacts, including, among other things, impacts on air quality, water quality, wildlife (including threatened and endangered species), historic and archaeological resources, geology, socioeconomics and aesthetics. NEPA also requires the consideration of alternatives to the project. The NEPA review process, especially the preparation of a full environmental impact statement, can be time consuming and expensive. Though NEPA requires only that an environmental evaluation be conducted and does not mandate a particular result, a federal agency could decide to deny a permit or impose certain conditions on its approval, based on its environmental review under NEPA, or a third party could challenge the adequacy of a NEPA review, which may result in a delay or cancellation of the issuance of a federal permit or approval.

Federal agencies granting permits for our operations also must consider impacts to endangered and threatened species and their habitat under the federal Endangered Species Act. We also must comply with, and are potentially subject to liability under the Endangered Species Act, which prohibits and imposes stringent penalties for the harming of endangered or threatened species and their habitat. Federal agencies also must consider a project’s impacts on historic or archaeological resources under the National Historic Preservation Act, and we may be required to conduct archaeological surveys of project sites and to avoid or preserve historical areas or artifacts.

State and Local Regulation

We are also subject to a variety of state and local environmental review and permitting requirements. Some states, including Wisconsin and Texas where our production facilities are located, have state laws similar to NEPA; thus our development of a new site or the expansion of an existing site may be subject to comprehensive state environmental reviews even if it is not subject to NEPA. In some cases, the state environmental review may be more stringent than the federal review. Our operations may require state-law based permits in addition to federal permits, requiring state agencies to consider a range of issues, many the same as federal agencies, including, among other things, a project’s impact on wildlife and their habitats, historic and archaeological sites, aesthetics, agricultural operations, and scenic areas. Wisconsin, Texas and some other states also have specific permitting and review processes for commercial silica mining operations, and state agencies may impose different or additional monitoring or mitigation requirements than federal agencies. The development of new sites and our existing operations also are subject to a variety of local environmental and regulatory requirements, including land use, zoning, building, and transportation requirements.

Certain local communities in which we operate, primarily in Wisconsin, have developed or are in the process of developing regulations or zoning restrictions intended to minimize the potential for dust to become airborne, control the flow of truck traffic, significantly restrict the area available for mining activities and require compensation to local residents for potential impacts of mining, among other regulatory initiatives. In addition, our existing permits granted by local regulatory authorities contain certain restrictions on such matters as hours of operation, permitted decibel levels and lighting, among other matters.

The regulatory framework in the jurisdictions in which we do business is potentially subject to amendments or modifications. Planned expansion of our existing facilities as well as the development of new facilities could be significantly impacted by increased regulatory activity. Delays or inability to obtain required permits for expansion of existing facilities, or the development of new facilities, as well as the increased costs of compliance with future state and local regulatory requirements could have a material negative impact on our ability to grow our business. In an effort to minimize these risks, we continue to be engaged with local communities in order to grow and maintain strong relationships with residents and regulators.

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Costs of Compliance

We may incur significant costs and liabilities as a result of environmental and worker health, and safety requirements applicable to our activities. Failure to comply with environmental laws and regulations may result in the assessment of sanctions, including administrative, civil and criminal penalties; imposition of investigatory, clean-up, and site restoration costs and liens or the incurrence of capital expenditures; the restriction, delay, denial or revocation of permits or other authorizations; and the issuance of injunctions to limit or cease some or all of our operations in a particular area. Compliance with these laws and regulations may also increase the cost of the development, construction, and operation of our projects and may prevent or delay the commencement or continuance of a given project. In addition, claims for injuries to persons or damages to natural resources and properties may result from environmental and other impacts of our activities.

The process for performing environmental impact studies and reviews for federal, state, and local permits required for our operations involves a significant investment of time and monetary resources. We cannot control the permit approval process. We cannot predict whether all permits required for a given project will be granted or whether such permits will be the subject of significant opposition. The denial of a permit essential to a project or the imposition of conditions with which it is not practicable or feasible to comply could impair or prevent our ability to develop a project. Significant opposition and delay in the environmental review and permitting process also could impair or delay our ability to develop a project. Additionally, the passage of more stringent environmental laws could impair our ability to develop new operations and have an adverse effect on our financial condition and results of operations.

Permits

We operate our facilities under a number of federal, state and local authorizations. We are required to have obtained permits, approvals and/or agreements in order to construct and operate our mining, processing, transloading and material handling facilities and operations in several states. These authorizations address environmental and worker health and safety conditions, and serve to protect public health and welfare. Historically, our properties allocated for mining, and all operational facilities and equipment, have obtained significant approvals necessary for excavation, extraction, and distribution of quality reserves however, there can be no assurance that such new or renewed approvals will be obtained in the future or that such future new or renewed approvals will not require increased costs or operating restrictions that could have a material adverse effect on our financial condition or results of operation.

New laws and regulations, amendment of existing laws and regulations, reinterpretation of legal requirements or increased governmental enforcement that relate to environmental requirements may result in increased compliance costs or additional operating restrictions which could have a material adverse effect on our business.

See Risk Factors under Item 1A of this Form 10-K for further discussion on environmental and mining-related permits and approvals.

Availability of Reports; Website Access; Other Information

Our internet address is http://www.hicrush.com. Through "Investors" — "SEC Filings" on our home page, we make available free of charge our Annual Report on Form 10-K, our Quarterly Reports on Form 10-Q, our Current Reports on Form 8-K, SEC Forms 3, 4 and 5 and any amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, or the Exchange Act, as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Reports filed with the SEC are also made available on its website at www.sec.gov.

ITEM 1A. RISK FACTORS

There are many factors that may affect our business, financial condition and results of operations and investments in us. Security holders and potential investors in our securities should carefully consider the risk factors set forth below, as well as the discussion of other factors that could affect us or investments in us included elsewhere in this Annual Report on Form 10-K. If one or more of these risks were to materialize, our business, financial condition or results of operations could be materially and adversely affected. These known material risks could cause our actual results to differ materially from those contained in any written or oral forward-looking statements made by us or on our behalf.

Risks Inherent in Our Business

Our business and financial performance depends on well completion activity in the oil and natural gas industry.

Demand for frac sand is materially dependent on the levels of activity in oil and natural gas exploration, development and production, and more specifically, the number of oil and natural gas wells completed in geological formations where proppants are used in hydraulic fracturing treatments and the amount of frac sand customarily used in the completion of such wells.

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Industry conditions that impact the activity levels of oil and natural gas producers are influenced by numerous factors over which we have no control, including:

• commodity prices;

• the cost of producing and delivering oil and natural gas;

• worldwide political, military, and economic conditions;

• governmental regulations, including the policies of governments regarding the exploration for and production and development of their oil and natural gas reserves;

• global weather conditions and natural disasters;

• development of alternative energy sources; and

• stockholder activism or activities by non-governmental organizations to restrict the exploration, development and production of oil and natural gas.

A prolonged reduction in oil and natural gas prices would generally depress the level of oil and natural gas exploration, development, production and well completion activity, which could result in a corresponding decline in the demand for the frac sand we produce and deliver. In addition, any future decreases in the rate at which oil and natural gas reserves are developed, whether due to increased governmental regulation, limitations on exploration and production activity or other factors, could have a material adverse effect on our business, even in a stronger oil and natural gas price environment. If there is a decrease in the demand for frac sand, we may be unable to sell or deliver volumes, or be forced to reduce our sales prices, any of which would reduce the amount of cash we generate.

Our operations are subject to operating risks that are often beyond our control and could adversely affect production levels and costs, and such risks may not be covered by insurance.

Our operations are subject to risks normally encountered in the commercial silica industry, some of which are beyond our control including the following:

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

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

• demand and pricing for our integrated logistics solutions;

• the pace of adoption of our integrated logistics solutions;

• the amount of frac sand we are able to timely deliver at the wellsite, which could be adversely affected by, among other things, logistics constraints, weather, or other delays at the wellsite or transloading facility;

• changes in prevailing economic conditions, including the extent of changes in crude oil, natural gas and other commodity prices;

• the amount of frac sand we are able to excavate and process, which could be adversely affected by, among other things, operating difficulties, cave-ins, pit wall failures, rock falls and unusual or unfavorable geologic conditions;

• changes in the price and availability of natural gas or electricity;

• inability to obtain necessary equipment or replacement parts;

• changes in the railroad infrastructure, price, capacity and availability, including the potential for rail line disruptions;

• changes in the road infrastructure, including the potential for trucking and other transportation disruptions;

• changes in the price and availability of transportation;

• extensive regulation of trucking services;

• volatility of fuel prices;

• availability of or failure of our contractors, partners and service providers to provide services at the agreed-upon levels or times;

• failure to maintain safe work sites at our facilities or by third parties at their work sites;

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

• environmental hazards, such as leaks and spills as well as unauthorized discharges of fluids or other pollutants into the surface and subsurface environment;

• industrial and transportation related accidents;

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• fires, explosions or other accidents;

• difficulty collecting receivables;

• inability of our customers to take delivery;

• difficulty or inability in obtaining, maintaining and renewing permits, including environmental permits or other licenses and approvals such as mining or water rights;

• facility shutdowns or restrictions in operations in response to environmental regulatory actions including but not limited to actions related to endangered species;

• systemic design or engineering flaws in the equipment we use to provide logistics services;

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

• the outcome of litigation, claims or assessments, including unasserted claims;

• challenges to or infringement upon our intellectual property rights;

• labor disputes and disputes with our third-party contractors;

• inability to attract and retain key personnel;

• cyber security breaches of our systems and information technology;

• our ability to borrow funds and access capital markets;

• changes in the foreign currency exchange rates in the countries that we conduct business; and

• changes in the political environment of the geographical areas in which we and our customers operate.

Our future performance will depend on our ability to succeed in competitive markets, and on our ability to appropriately react to potential fluctuations in the demand for and supply of frac sand.

We operate in a highly competitive market that is characterized by a small number of large, national companies and a larger number of small, regional or local companies in the production, distribution and logistics of frac sand. Competition in the industry is based on price, reliability of supply, transportation capabilities, product quality, performance and sand characteristics.

We compete with large, national companies such as U.S. Silica Holdings, Inc., Covia Holdings Corporation, and others. Our competitors may have greater financial and other resources than we do, may develop technology superior to ours or may have production and distribution facilities or last mile delivery solutions that are significantly advantaged over ours. Should the demand for hydraulic fracturing services decrease, prices in the frac sand market could materially decrease as competitors may sell frac sand at below market prices. In addition, E&P's and other providers of hydraulic fracturing services could compete directly with us, which may negatively impact pricing and demand for our frac sand and related services. Because the markets for our products and logistic services are typically local, we also compete with smaller regional or local companies. If demand for hydraulic fracturing services decreases and the supply of frac sand available in the market increases, prices in the frac sand market could continue to materially decrease Furthermore, our competitors may choose to consolidate, which could provide them with greater financial and other resources than us. We may not be able to compete successfully against our competitors in the future, and competition could have a material adverse effect on our business, financial condition, results of operations and cash flows.

We may be adversely affected by decreased demand for raw frac sand due to the development of either effective alternative proppants or new processes to replace hydraulic fracturing.

Raw frac sand is a proppant used in the completion and re-completion of oil and natural gas wells to stimulate and maintain oil and natural gas production through the process of hydraulic fracturing. Raw frac sand is the most commonly used proppant and is less expensive than other proppants, such as resin-coated sand and manufactured ceramics. A significant shift in demand from frac sand, including from the types of raw frac sand product that we produce and sell to other proppants, or the development of new processes to replace hydraulic fracturing altogether, could cause a decline in the demand for the frac sand we produce and result in a material adverse effect on our financial condition and results of operations.

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The majority of our sales are generated under contracts with companies in the oil and natural gas industry. The loss of a contract or customer, a significant reduction in purchases by any customer, our customers' failure to comply with contract terms, or our inability to renegotiate, renew or replace our existing contracts on favorable terms could, individually or in the aggregate, adversely affect our business, financial condition and results of operations.

As of January 1, 2019, we have contracted to sell raw frac sand under long-term supply agreements to customers with remaining terms ranging from 15 to 72 months. For the year ended December 31, 2018, we generated 87% of our revenues from sales of frac sand to customers with whom we had long-term contracts. A substantial portion of our logistics services are provided to customers with whom we have long-term agreements as defined in a MSA and related work orders.  The MSA and related work orders are typically separate from any sand supply contract we may have with the same customer.

Some of our customers have exited or could exit the business, or have been or could be acquired by other companies that purchase the same products and logistic services we provide from other third-party providers. Our current customers also may seek to acquire frac sand or logistic services from other providers that offer more competitive pricing or capture and develop their own sources of frac sand. The loss of a customer or contract, or a reduction in the amount of frac sand or logistic services purchased by any customer, could have an adverse effect on our business, financial condition and results of operations.

Our customers may fail to comply with the terms of their existing contracts. Our enforcement of specific contract terms may be limited by market dynamics and other factors. A customer's failure to comply with contract terms or our limited enforcement thereof could have an adverse effect on our business, financial condition and results of operations.

Upon the expiration of our current contracts, our customers may not continue to purchase the same levels of our frac sand or logistics services due to a variety of reasons. In addition, we may choose to renegotiate our existing contracts on less favorable terms or at reduced volumes in order to preserve relationships with our customers. Upon the expiration of our current contract terms, we may be unable to renew our existing contracts or enter into new contracts on terms favorable to us, or at all. Any renegotiation of our contracts on less favorable terms, or inability to enter into new contracts on economically acceptable terms upon the expiration of our current contracts, could have an adverse effect on our business, financial condition and results of operations.

Our long-term contracts may preclude us from mitigating the effect of increased operational costs during the term of our long-term contracts, even though certain volumes under certain of our long-term contracts are subject to annual fixed price escalators or other pricing adjustment mechanisms.

The pricing arrangements under our long-term supply contracts we have may negatively impact our results of operations. If our operational costs increase during the terms of our long-term supply contracts, we may not be able to pass any of those increased costs to our customers. If we are unable to otherwise mitigate these increased operational costs, our net income and available cash for distributions could decline. Additionally, in periods with increasing prices, our sales may not keep pace with market prices.

We are subject to the credit risk of our customers, and any material nonpayment or nonperformance by our customers could adversely affect our financial results.

We are subject to the risk of loss resulting from nonpayment or nonperformance by our customers, whose operations are concentrated in a single industry, the global oil and natural gas industry. In particular, as a result of volatility in oil and natural gas prices and ongoing uncertainty of the global economic environment our customers may not be able to fulfill their existing commitments or access financing necessary to fund their current or future obligations. Our credit procedures and policies may not be adequate to fully eliminate customer credit risk. If we fail to adequately assess the creditworthiness of existing or future customers or unanticipated deterioration in their creditworthiness, any resulting increase in nonpayment or nonperformance by them and our inability to re-market or otherwise sell the volumes could have a material adverse effect on our business, financial condition and results of operations.

We have outstanding Senior Notes and have entered into an ABL Credit Facility which contain restrictions that may restrict our business and financing activities.

Our Senior Notes and ABL Credit Facility place financial restrictions and operating restrictions on our business, which may limit our flexibility to respond to opportunities and may harm our business, financial condition and results of operations.

The operating and financial restrictions and covenants in our Senior Notes and ABL Credit Facility restrict, and any other future financing agreements that we may enter into could restrict, our ability to finance future operations or capital needs, to engage in, expand or pursue our business activities or to make distributions to our unitholders. Additionally, our Senior Notes and ABL Credit Facility restrict our ability to, among other things:

• incur additional indebtedness;

• incur liens on property;

• make certain investments;

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• enter into a merger, consolidate or acquire capital in or assets of other entities;

• sell assets;

• make restricted payments; and

• enter into transactions with affiliates.

Our compliance with these provisions may materially adversely affect our ability to react to changes in market conditions, take advantage of business opportunities we believe to be desirable, obtain future financing, fund needed capital expenditures, finance acquisitions, equipment purchases and development expenditures, or withstand a future downturn in our business.

Our ability to comply with any such restrictions and covenants is uncertain and will be affected by the levels of cash flow from our operations and events or circumstances beyond our control. If market or other economic conditions deteriorate, our ability to comply with these restrictions or covenants may be impaired. If we violate any of the restrictions or covenants in the Senior Notes or ABL Credit Facility, a significant portion of our indebtedness may become immediately due and payable and our lenders’ commitment to make further loans to us may terminate. We may not have, or be able to obtain, sufficient funds to make these accelerated payments. Even if we could obtain alternative financing, that financing may not be on terms that are favorable or acceptable to us. If we are unable to repay amounts borrowed, the holders of the debt could initiate a bankruptcy proceeding or liquidation proceeding against the collateral. In addition, our obligations under our Senior Notes or ABL Credit Facility are secured by substantially all of our assets and if we are unable to repay our indebtedness as required under these facilities, the lenders could seek to foreclose on our assets.

Our long-term Senior Notes debt is currently rated by Moody's Investors Service Inc. ("Moody's") and Standard and Poor’s ("S&P"). As of February 14, 2019, the credit rating of the Partnership’s Senior Notes was B3 from Moody’s and B- from Standard and Poor’s. Any future downgrades in our credit ratings could negatively impact the cost of raising capital, and a downgrade could also adversely affect our ability to effectively execute aspects of our strategy and to access capital in the public markets.

Increases in interest rates could adversely affect our business and results of operations.

We have exposure to increases in interest rates under our ABL Credit Facility. As of December 31, 2018, we had no borrowings outstanding under our ABL Credit Facility. To the extent there are any outstanding borrowings under the ABL Credit Facility, changes in applicable interest rates would not affect the ABL Credit Facility’s fair market value, but could adversely affect our future results of operations and cash flows.

In addition, the ABL Credit Facility uses LIBOR as a benchmark for establishing the interest rate.  LIBOR is the subject of recent proposals for reform.  In July 2017, the United Kingdom’s Financial Conduct Authority, which regulates LIBOR, announced that it intends to phase out LIBOR by the end of 2021.  LIBOR may disappear entirely or may perform differently than in the past.  The consequences with respect to LIBOR cannot be predicted but could result in an increase in the cost of our variable interest rate under the ABL Credit Facility.

We may be required to make substantial capital expenditures to maintain, develop and increase our asset base. The inability to obtain needed capital or financing on satisfactory terms, or at all, could have an adverse effect on our growth and profitability.

Although we have used a significant amount of our cash reserves and cash generated from our operations to fund the development and expansion of our asset base, we may depend on the availability of credit to fund future capital expenditures. Our ability to obtain bank financing or to access the capital markets for future equity or debt offerings may be limited by our financial condition at the time of any such financing or offering, the restrictions and covenants contained in our Senior Notes, ABL Credit Facility or other future debt agreements, adverse market conditions or other contingencies and uncertainties that are beyond our control. Our failure to obtain the funds necessary to maintain, develop and increase our asset base could adversely impact our growth and profitability.

Even if we are able to obtain financing or access the capital markets, incurring additional debt may significantly increase our interest expense and financial leverage, and our level of indebtedness could restrict our ability to fund future development and acquisition activities. In addition, the issuance of additional equity interests may result in dilution to our existing unitholders.

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Our expansion or modification of existing assets, or the construction of new assets, may not result in revenue increases and may be subject to regulatory, environmental, political, legal and economic risks, which could adversely affect our results of operations and financial condition.

The construction of new facilities, additions or modifications to our existing facilities, or equipment may require the expenditure of significant amounts of capital. If we undertake these projects, they may not be completed on schedule or at the budgeted cost or at all. Moreover, upon the expenditure of future funds on a particular project, our revenues may not increase immediately, or as anticipated, or at all. For instance, we may construct new facilities over an extended period of time and will not receive any material increases in revenues until the projects are completed. Moreover, we may expend capital to capture anticipated future growth in a location in which such growth does not materialize. Since we are not engaged in the hydraulic fracturing process, we may be unable to accurately predict the extent of well completion activity to take place in future periods. To the extent we rely on estimates of future levels of well completion activity in any decision to construct facilities, such estimates may prove to be inaccurate because there are numerous uncertainties inherent in forecasting levels of well completion activity. In addition, our assets may be subject to numerous regulatory, environmental, political and legal uncertainties which could negatively impact our ability to capture anticipated economic benefits. Our expansion or modification of existing or new assets may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our results of operations and financial condition.

Any adverse developments at our production facilities could have an adverse effect on our financial condition and results of operations.

Any adverse development at our production facilities due to catastrophic events or weather, or any other event that would cause us to curtail, suspend or terminate operations at the production facilities, could result in us being unable to meet our contracted sand deliveries to our customers. If we are unable to deliver contracted volumes within the required time frame, or otherwise arrange for delivery from a third party, we could be required to pay make-whole payments to our customers that could have an adverse effect on our financial condition and results of operations. If we are unable to provide supply from our production facilities, any reduction in the amount of frac sand available for our purchase from third parties could have an adverse effect on our business, financial condition and results of operations.

Inaccuracies in estimates of volumes and qualities of our sand reserves could result in lower than expected sales and higher than expected production costs.

John T. Boyd, our independent reserve engineers, prepared estimates of our reserves based on engineering, economic and geological data assembled and analyzed by our engineers and geologists. However, frac sand reserve estimates are by nature imprecise and depend to some extent on statistical inferences drawn from available data, which may prove unreliable. There are numerous uncertainties inherent in estimating quantities and qualities of reserves and non-reserve frac sand deposits and costs to mine recoverable reserves, including many factors beyond our control. Estimates of economically recoverable frac sand reserves necessarily depend on a number of factors and assumptions, all of which may vary considerably from actual results, such as:

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

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

• assumptions concerning future effects of regulation, including the issuance of required permits and taxes by governmental agencies.

Any inaccuracy in John T. Boyd’s estimates related to our frac sand reserves and non-reserve frac sand deposits could result in lower than expected sales and higher than expected costs. For example, John T. Boyd’s estimates of our proven reserves assume that our revenue and cost structure will remain relatively constant over the life of our reserves. If these assumptions prove to be inaccurate, some or all of our reserves may not be economically mineable, which could have a material adverse effect on our results of operations and cash flows. In addition, we pay a fixed price per ton of sand excavated regardless of the quality of the frac sand, and our current customer contracts require us to deliver frac sand that meets certain specifications. If John T. Boyd’s estimates of the quality of our reserves, including the volumes of the various specifications of those reserves, prove to be inaccurate, we may incur significantly higher excavation costs without corresponding increases in revenues, we may not be able to meet our contractual obligations, or our facilities may have a shorter than expected reserve life, which could have a material adverse effect on our results of operations and cash flows.

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Our operations are dependent on our rights and ability to mine our properties and on our having received or renewed the required permits and approvals from governmental authorities and other third parties.

We hold numerous governmental, environmental, mining, and other permits, water rights, and approvals authorizing operations at our production facilities in Wisconsin and Texas as well as our terminal facilities. For our extraction and processing, the permitting process is subject to federal, state and local authority. For example, on the federal level, a Mine Identification Request (MSHA Form 7000-51) must be filed and obtained before mining commences. If wetlands are implicated, a Corps Wetland Permit is required. At the state level, a series of permits and approvals are required related to air quality, wetlands, water quality (waste water, stormwater), grading permits, endangered species, archaeological assessments, and high capacity wells in addition to others depending upon site-specific factors and operational detail. At the local level, zoning, building, stormwater, erosion control, wellhead protection, road usage and access, among other matters are all regulated and require permitting or approval to some degree. Additionally a non-metallic mining reclamation permit is required for our Wisconsin production facilities while an Aggregate Production Operations permit is required for our Texas production facilities. A decision by a governmental agency or other third party to deny or delay issuing a new or renewed permit or approval, or to revoke or substantially modify an existing permit or approval, whether for development of new facilities or expansion of existing facilities, could have a material adverse effect on our ability to continue operations.

Title to, and the area of, mineral properties and water rights may also be disputed. Mineral properties sometimes contain claims or transfer histories that examiners cannot verify. Legal challenges successfully claiming that we do not have title to our property or lack appropriate water rights could cause us to lose any rights to explore, develop, and extract minerals, without compensation for our prior expenditures relating to such property. Our business may suffer a material adverse effect in the event we have title deficiencies.

In some instances, we have received access rights or easements from third parties, which allow for a more efficient operation than would exist without the access or easement. A third party could take legal action to restrict or suspend the access or easement, and any such action could be materially adverse to our business, results of operations or financial condition.

Laws and regulations relating to hydraulic fracturing could increase our costs of doing business and result in additional operating restrictions, delays or cancellations in completion of new oil and natural gas wells by our customers, which could cause a decline in the demand for our frac sand and have a material adverse effect on our business, financial condition and results of operations.

Although we do not directly engage in hydraulic fracturing activities, our customers purchase our frac sand for use in their hydraulic fracturing activities. Increased regulation of hydraulic fracturing may adversely impact our business, financial condition and results of operations. The federal Safe Drinking Water Act ("SDWA") regulates the underground injection of substances through the Underground Injection Control Program ("UIC Program"). Currently, with the exception of certain hydraulic fracturing activities involving the use of diesel, hydraulic fracturing is exempt from federal regulation under the UIC Program, and the hydraulic fracturing process is typically regulated by state or local governmental authorities. However, the practice of hydraulic fracturing has become a contentious subject, attracting considerable public attention and continues to undergo political and regulatory scrutiny. From time to time, Congress has considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process but no comprehensive hydraulic fracturing legislation at the federal level has been implemented, to date.

There is also the potential for increased federal regulations governing various environmental aspects of hydraulic fracturing and the oil and natural gas production industry.  In recent years, the EPA has finalized rules to limit air emissions from the hydraulic fracturing of certain oil and natural gas wells and to regulate other sources of air emissions from production operations.  The EPA also finalized wastewater effluent guidelines for unconventional oil and natural gas operations.  Likewise, the Bureau of Land Management ("BLM") finalized rules increasing compliance and disclosure obligations for hydraulic fracturing operations but those final rules were subsequently rescinded by the BLM and are currently the subject of pending litigation.  Although the BLM rules have been rescinded or delayed, they are the subject of litigation that could result in the rules becoming effective.  Further, the EPA, BLM, or other federal agencies could promulgate new, amended, or replacement rules for hydraulic fracturing and oil and natural gas operations.

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As noted previously under Item 1, "Business-Environmental and Occupational Safety and Health Regulation-Environmental Matters", the RCRA and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and clean-up of hazardous and, in some circumstances, non-hazardous wastes. From time to time various environmental groups have challenged the EPA’s exclusion of certain oil and natural gas wastes from regulation as hazardous wastes under RCRA. For example, pursuant to a consent decree issued by a federal district court, the EPA is required to propose by no later than March 15, 2019 a rulemaking for revision of certain RCRA Subtitle D regulations that could result in such oil and natural gas wastes being regulated as hazardous wastes, or sign a determination that revision of those RCRA regulations is unnecessary. A loss of the RCRA exclusion for drilling fluids, produced waters and related wastes, if EPA were to eliminate the exclusion, could increase our costs to manage and dispose of the wastes we generate as well as increase our customers’ waste management costs, which could result in a decrease of those customers' drilling activity, either of which developments could have a material adverse effect on our business results of operations and financial performance.

In addition to federal laws and regulations, various state and local governments have implemented, or are considering, increased regulatory oversight of hydraulic fracturing through additional permitting requirements, operational restrictions, disclosure requirements, and temporary or permanent bans on hydraulic fracturing in certain areas such as environmentally sensitive watersheds. Local governments also may seek to adopt ordinances to regulate or severely restrict the time, place and manner of hydraulic fracturing activities within their jurisdictions. Moreover, non-governmental organizations may seek to restrict hydraulic fracturing, such as was the case in Colorado where certain interest groups therein have unsuccessfully pursued ballot initiatives in recent general election cycles that, had they been successful, would have revised the state constitution or state statutes in a manner that would have made exploration and production activities in the state more difficult or expensive in the future, including, for example, by increasing mandatory setbacks of oil and natural gas operations from certain occupied structures and environmentally-sensitive or recreational areas.

The adoption of new or more stringent laws or regulations at the federal, state and local levels imposing reporting obligations on, or otherwise limiting or delaying, the hydraulic fracturing process could make it more difficult to complete oil and natural gas wells, increase our customers’ costs of compliance and doing business, and otherwise adversely affect the hydraulic oil and natural gas fracturing services they perform, which could negatively impact demand for our frac sand. In addition, heightened political, regulatory, and public scrutiny of hydraulic fracturing practices could expose us or our customers to increased legal and regulatory proceedings, which could be time-consuming, costly, or result in substantial legal liability or significant reputational harm. We could be directly affected by adverse litigation involving us, or indirectly affected if the cost of compliance limits the ability of our customers to operate. Such costs and scrutiny could directly or indirectly, through reduced demand for our frac sand, have a material adverse effect on our business, financial condition and results of operations.

A facility closure or long-term idling entails substantial costs, and if we close our production facilities sooner than anticipated, our results of operations may be adversely affected.

The Augusta facility was temporarily idled from October 2015 until production resumed in September 2016 and the Whitehall facility was temporarily idled during the second quarter of 2016 and resumed production in March 2017. In September 2018, the Partnership temporarily idled dry plant operations at the Whitehall facility. In January 2019, the Partnership resumed operations at the Whitehall facility and temporarily idled the Augusta facility.

If we idle our production facilities for a long period of time or close a facility sooner than expected, sales will decline unless we are able to acquire and develop additional facilities, which may not be possible. The closure of a production facility would involve significant fixed closure costs, including accelerated employment legacy costs, severance-related obligations, reclamation and other environmental costs and the costs of terminating long-term obligations, including energy contracts and equipment leases. We accrue for the costs of reclaiming open pits, stockpiles, non-saleable sand, ponds, roads and other mining support areas over the estimated mining life of our property. We base our assumptions regarding the life of our production facilities on detailed studies that we perform from time to time, but our studies and assumptions may not prove to be accurate. If we were to reduce the estimated life of our production facilities, the fixed facility closure costs would be applied to a shorter period of production, which would increase production costs per ton produced and could materially and adversely affect our results of operations and financial condition.

Applicable statutes and regulations require that mining property be reclaimed following a mine closure in accordance with specified standards and an approved reclamation plan. The plan addresses matters such as removal of facilities and equipment, regrading, minimizing or preventing erosion and limiting the potential for sediment run-off into surface waters other forms of water pollution, re-vegetation and post-mining land use. We are required to post a surety bond or other form of financial assurance equal to the cost of reclamation as set forth in the approved reclamation plan. The establishment of the final mine closure reclamation liability is based on permit requirements and requires various estimates and assumptions, principally associated with reclamation costs and production levels. If our accruals for expected reclamation and other costs associated with facility closures for which we will be responsible were later determined to be insufficient, our business, results of operations and financial condition would be adversely affected.

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Given the nature of our frac sand mining and processing operations, we face a material risk of liability, delays and increased cash costs of production from environmental and industrial accidents as well as due to operational breakdowns.

Our business involves significant risks and hazards, including environmental hazards, industrial accidents, and breakdowns of equipment and machinery. Our business is exposed to hazards associated with frac sand mining, processing and the related storage, handling and transportation of raw materials, products and wastes. Furthermore, during operational breakdowns, the relevant facility may not be fully operational within the anticipated timeframe, which could result in further business losses. The occurrence of any of these or other hazards could delay production, suspend operations, increase repair, maintenance or medical costs and, due to the integration of our facilities, could have an adverse effect on the productivity and profitability of a particular facility or on our business as a whole. Incidents of this nature have occurred in the past and may happen again in the future. We have insurance policies for industrial, environmental and other accidents, but such policies are limited by their terms and may not cover certain risks in their entirety or at all.

Our production process consumes large amounts of natural gas and electricity. An increase in the price or a significant interruption in the supply of these or any other energy sources could have a material adverse effect on our financial condition or results of operations.

Energy costs, primarily natural gas and electricity, represented 2% of our total sales and 10% of our total production costs during the year ended December 31, 2018. Natural gas is the primary fuel source used for drying in the frac sand production process and, as such, our profitability is impacted by the price and availability of natural gas we purchase from third parties. Because we have not contracted for the provision of natural gas on a fixed-price basis, our costs and profitability will be impacted by fluctuations in prices for natural gas. The price and supply of natural gas are unpredictable and can fluctuate significantly based on international, political and economic circumstances, as well as other events outside our control, such as changes in supply and demand due to weather conditions, actions by OPEC and other oil and natural gas producers, regional production patterns and environmental concerns. In addition, potential climate change regulations or carbon or emissions taxes could result in higher production costs for energy, which may be passed on to us in whole or in part. The price of natural gas has been extremely volatile over the last several years. In order to manage this risk, we may hedge natural gas prices through the use of derivative financial instruments, such as forwards, swaps and futures. However, these measures carry risk (including nonperformance by counterparties) and do not in any event entirely eliminate the risk of decreased margins as a result of natural gas price increases. A significant increase in the price of energy that is not recovered through an increase in the price of our products or covered through hedging arrangements or an extended interruption in the supply of natural gas or electricity to our production facilities could have a material adverse effect on our business, financial condition, results of operations, cash flows and prospects.

Seasonal and severe weather conditions could have a material adverse impact on our business.

Our business could be materially adversely affected by seasonal and severe weather conditions. Severe weather conditions may affect our customers’ operations, thus reducing their need for our products or ability to take delivery of our product at the terminal or the wellsite, or impact our operations by resulting in weather-related damage to our facilities and equipment and impact our customers’ ability to take delivery of our products at our plant site. Additionally, some scientists have concluded that increasing concentrations of GHGs in the atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climate events. Any weather-related interference with our operations could force us to delay or curtail services and potentially breach our contractual obligations to deliver minimum volumes or result in a loss of productivity and an increase in our operating costs.

In addition, severe winter weather conditions impact our Wisconsin operations by causing us to halt our excavation and wet plant related production activities during the winter months. During non-winter months, we excavate and process excess sand to build a sufficient washed sand stockpile that feeds the dry plant. Unexpected winter conditions (e.g., if winter conditions come earlier than expected or last longer than expected) may result in us not having a sufficient sand stockpile to supply feedstock for our dry plant during winter months, which could result in us being unable to meet our contracted sand deliveries during such time and lead to a material adverse effect on our business, financial condition, results of operation and reputation.

Our cash flow fluctuates on a seasonal basis.

Our cash flow is affected by a variety of factors, including weather conditions and seasonal periods. Seasonal fluctuations in weather impact the production levels at our wet processing plant and the level of completion activity in-basin. While our sales and finished product production levels are contracted annually and expected to be fulfilled evenly throughout the year, varying levels of wet plant production and in-basin demand can lead to cash flows fluctuating through the year. For example, our mining and wet sand processing activities at our Wisconsin facilities are limited to non-winter months and while the wet processing plant is not operating, we will perform annual maintenance activities, the majority of which are expensed. As a consequence of the seasonality we may experience lower cash costs and higher expense in the first and fourth quarter of each calendar year.

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Diminished access to water may adversely affect our operations.

The excavation and processing activities in which we engage require significant amounts of water, of which we seek to recycle a significant percentage in our operating process. As a result, securing water rights and water access to sufficient volumes of water is necessary for the operation of our processing facilities. If future excavation and processing activities are located in an area that is water-constrained, there may be additional costs associated with securing sufficient water access. We have obtained water rights that we currently use to service the activities on our properties, and we plan to obtain all required water rights to service other properties we may develop or acquire in the future. However, the amount of water that we are entitled to use pursuant to our water rights must be determined by the appropriate regulatory authorities in the jurisdictions in which we operate. Such regulatory authorities may amend the regulations regarding such water rights, increase the cost of maintaining such water rights or eliminate our current water rights, and we may be unable to retain all or a portion of such water rights. These new regulations, which could also affect local municipalities and other industrial operations, could have a material adverse effect on our operating costs if implemented. Such changes in laws, regulations or government policy and related interpretations pertaining to water rights may alter the environment in which we do business, which may have an adverse effect on our financial condition and results of operations. Additionally, one or more water discharge permits may be required to properly dispose of water, including wastewater and stormwater at our processing sites. The water discharge permitting process is also subject to regulatory discretion, and any inability or delay in obtaining the necessary permits could have an adverse effect on our business financial condition and results of operations.

Failure to maintain effective quality control systems at our facilities and operations could have a material adverse effect on our business and operations.

The performance and quality of our products and logistic services are critical to the success of our business. These factors depend significantly on the effectiveness of our quality control systems, which, in turn, depends on a number of factors, including the design of our quality control systems, our quality-training program and our ability to ensure that our employees adhere to our quality control policies and guidelines. Any significant failure or deterioration of our quality control systems or adherence to our training in implementing such systems could have a material adverse effect on our business, financial condition, results of operations and reputation.

If we are unable to make acquisitions on economically acceptable terms or unable to successfully integrate the businesses we acquire, our future growth could be limited, and any acquisitions we make may reduce, rather than increase, our cash generated from operations on a per unit basis.

A portion of our strategy to grow our business and return capital to unitholders is dependent on our ability to make acquisitions that result in an increase in our cash available for distribution per unit or unit repurchases. If we are unable to make acquisitions because we are unable to identify attractive acquisition candidates or negotiate acceptable acquisition agreements, we are unable to obtain financing for these acquisitions on economically acceptable terms or we are outbid by competitors, our future growth and ability to increase distributions may be limited. Furthermore, even if we do consummate acquisitions that we believe will be accretive, they may in fact result in a decrease in our cash available for distribution per unit or unit repurchases. Any acquisition involves potential risks, some of which are beyond our control, including, among other things:

• inaccurate assumptions about revenues and costs, including synergies;

• inability to successfully integrate the businesses we acquire;

• inability to hire, train or retain qualified personnel to manage and operate our business and newly acquired assets;

• the assumption of unknown liabilities, including environmental liabilities;

• limitations on rights to indemnity from the seller;

• mistaken assumptions about the overall costs of equity or debt;

• the diversion of management’s attention from other business concerns;

• unforeseen difficulties operating in new product areas or new geographic areas; and

• customer or key employee losses at the acquired businesses.

If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and unitholders will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.

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Our business may suffer if we lose, or are unable to attract and retain, key personnel.

We depend to a large extent on the services of our senior management team and other key personnel. Members of our senior management and other key employees have extensive experience and expertise in the frac sand and logistics services business, as well as substantial experience and relationships with participants in the exploration and production and oilfield services industries. Competition for management and key personnel is intense, and the pool of qualified candidates is limited. The loss of any of these individuals or the failure to attract additional personnel, as needed, could have a material adverse effect on our operations and could lead to higher labor costs or the use of less-qualified personnel. In addition, if any of our executives or other key employees were to join a competitor or form a competing company, we could lose customers, suppliers, know-how and key personnel. Our success will be dependent on our ability to continue to attract, employ and retain highly skilled personnel.

A shortage of skilled labor together with rising labor costs in the industry may further increase operating costs, which could adversely affect our results of operations.

Efficient sand production and delivery requires skilled laborers, preferably with several years of experience and proficiency in multiple tasks. Our operations also utilize third-party contractors. There may be a shortage of skilled labor required throughout our operations in various locations. If the shortage of experienced skilled labor continues or worsens, we may find it difficult to retain or replace third-party contractors, and we may be unable to retain, attract and hire or train the necessary number of skilled laborers to perform our own operations. In either event, there could be an adverse impact on our labor productivity and costs and our ability to conduct operations.

We do not own the land on which the majority of our terminal facilities are located, which could disrupt our operations.

We do not own the land on which the majority of our terminals are located and instead own leasehold interests and rights-of-way for the operation of these facilities.  Upon expiration, termination or other lapse of our current leasehold terms, we may be unable to renew our existing leases or rights-of-way on terms favorable to us, or at all.  Any renegotiation on less favorable terms or inability to enter into new leases on economically acceptable terms upon the expiration, termination or other lapse of our current leases or rights-of-way could cause us to cease operations on the affected land, increase costs related to continuing operations elsewhere and have a material adverse effect on our business, financial condition and results of operations.

Fluctuations in transportation costs and the availability or reliability of rail transportation could reduce revenues by causing us to reduce our production or by impairing the ability of our customers to take delivery.

Transportation costs represent a significant portion of the total delivered cost of frac sand for our customers and, as a result, the cost of transportation is a critical factor in a customer’s purchasing decision. Disruption of transportation services due to shortages of rail cars or trucks, weather-related problems, flooding, drought, accidents, mechanical difficulties, strikes, lockouts, bottlenecks or other events could temporarily impair our ability to supply our customers through our logistics network of rail-based terminals, or our last mile operations or, if our customers are not using our transportation services, the ability of our customers to take delivery of frac sand. Accordingly, if there are disruptions of the rail transportation or trucking services utilized by ourselves or our customers, our business could be adversely affected.

Increases in the price of diesel fuel may adversely affect our results of operations.

Diesel fuel costs and rail fuel surcharges generally fluctuate with increasing and decreasing world crude oil prices, and accordingly are subject to political, economic and market factors that are outside of our control. Our operations are dependent on earthmoving equipment, railcars and tractor trailers, and diesel fuel costs are a significant component of the operating expense of these vehicles. We contract with a third party to excavate raw frac sand, deliver the raw frac sand to our processing facility and move the sand from our wet plant to our dry plant, and pay a fixed price per ton of sand delivered to our wet plant, subject to a fuel surcharge based on the price of diesel fuel. Rail transportation and trucking rates are generally subject to varying fuel surcharges based on the price of diesel fuel. Accordingly, increased diesel fuel costs could have an adverse effect on our results of operations and cash flows.

We face distribution and logistics challenges in our business.

As oil and natural gas prices fluctuate, our customers may shift their focus back and forth between different resource plays, some of which can be located in geographic areas that do not have well-developed transportation and distribution infrastructure systems. Transportation and logistics operating expenses comprise a significant portion of our total delivered cost of sales. Therefore, serving our customers in these less-developed areas presents distribution and other operational challenges that may affect our sales and negatively impact our operating costs. Disruptions in transportation services, including shortages of railcars or trucks, or a lack of developed infrastructure, could affect our ability to timely and cost effectively deliver to our customers and could provide a competitive advantage to competitors located in closer proximity to our customers. Additionally, increases in the price of transportation costs, including freight charges, fuel surcharges, terminal switch fees and demurrage costs, excess railcars or trucking rates could negatively impact operating costs if we are unable to pass those increased costs along to our customers. Failure to find long-term solutions to these logistics challenges could adversely affect our ability to respond quickly to the needs of our customers or result in additional increased costs, and thus could negatively impact our results of operations and financial condition.

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The amount of cash we have available for return of capital to holders of our units depends primarily on our cash flow and not solely on profitability, which may prevent us from making cash distributions during periods when we record net income.

The amount of cash we have available for distribution depends primarily upon our cash flow, including cash flow from reserves and working capital or other borrowings, and not solely on profitability, which will be affected by non-cash items. As a result, we may pay cash distributions during periods when we record net losses for financial accounting purposes and may not pay cash distributions during periods when we record net income.

In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including:

• the level of capital expenditures we make;

• our debt service requirements and other liabilities;

• fluctuations in our working capital needs;

• the cost of acquisitions;

• the amount of unit repurchases we make;

• our ability to borrow funds and access capital markets;

• restrictions contained in debt agreements to which we are a party; and

• the amount of cash reserves established by our general partner.

Our operations are subject to operational hazards and unforeseen interruptions for which we may not be adequately insured.

Our operations are exposed to potential natural disasters, including blizzards, tornadoes, storms, floods and earthquakes. If any of these events were to occur, we could incur substantial losses because of personal injury or loss of life, severe damage to and destruction of property and equipment, and pollution or other environmental damage resulting in curtailment or suspension of our operations.

We believe we carry adequate insurance, but we may not be fully insured against all risks incident to our business, including the risk of our operations being interrupted due to severe weather and natural disasters. Furthermore, we may be unable to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies could increase. In addition, sub-limits have been imposed for certain risks. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. If we were to incur a significant liability for which we are not fully insured, it could have a material adverse effect on our financial condition, results of operations and cash available for distribution to unitholders.

A terrorist attack or armed conflict could harm our business.

Terrorist activities, anti-terrorist efforts and other armed conflicts involving the United States could adversely affect the United States and global economies and could prevent us from meeting financial and other obligations. We could experience loss of business, delays or defaults in payments from payors or disruptions of fuel supplies and markets if pipelines, production facilities, processing plants or refineries are direct targets or indirect casualties of an act of terror or war. Additionally, destructive forms of protest and opposition by extremists and other disruptions, including acts of sabotage or eco-terrorism, against oil and natural gas development and production activities could potentially result in damage or injury to persons, property or the environment or lead to extended interruptions of our or our clients’ operations. Such activities could reduce the overall demand for oil and natural gas, which, in turn, could also reduce the demand for our frac sand. Terrorist activities and the threat of potential terrorist activities and any resulting economic downturn could adversely affect our results of operations, impair our ability to raise capital or otherwise adversely impact our ability to realize certain business strategies.

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We are subject to cyber security risks. A cyber incident could occur and result in information theft, data corruption, operational disruption and/or financial loss.

The oil and natural gas industry has become increasingly dependent on digital technologies to conduct certain processing activities. For example, we depend on digital technologies to perform many of our services and to process and record financial and operating data. In addition, in the ordinary course of our business, we collect and store sensitive data, including our proprietary business information and personally identifiable information of our employees in our data centers and on our networks. The secure processing, maintenance and transmission of this information is important to our operations. At the same time, cyber incidents, including deliberate attacks, have increased. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cyber security threats. Our technologies, systems and networks, and those of our vendors, suppliers and other business partners, may become the target of cyber attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period. Our systems and insurance coverage for protecting against cyber security risks may not be sufficient. As cyber incidents continue to evolve, we will likely be required to expand additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents. The audit committee is responsible for cyber oversight.

Risks Related to Environmental, Mining and Other Regulation

We and our customers are subject to extensive environmental and occupational health and safety laws and regulations that impose, and will continue to impose, significant costs and liabilities. In addition, future new or amended legal requirements, or more stringent interpretation or enforcement of existing requirements, could increase those costs and liabilities, which could adversely affect our results of operations.

We are subject to extensive federal, state, and local environmental and occupational health and safety laws and regulations governing the mining and mineral processing industry, including among other things, those relating to health and safety aspects of our operations, environmental permitting and licensing, air emissions and water discharges, water pollution and soil and groundwater contamination, waste management, hazardous materials, land use, remediation, reclamation and restoration of properties, wildlife protection, and natural resources. These laws and regulations, and the permits implemented thereunder have had, and will continue to have, a significant effect on our business. Environmental laws may impose substantial penalties for noncompliance, and certain of these laws, such as CERCLA, may impose strict, retroactive, and joint and several liability for the removal or remediation of releases of hazardous substances or property contamination, regardless of whether we or third parties were responsible for such release and even if our conduct was lawful at the time it occurred. Additionally, we may incur liability associated with releases of materials into the environment or for injuries to persons or damages to properties and natural resources, and such liability may potentially impair our ability to conduct our operations. Future environmental laws and regulations could restrict our ability to expand our facilities or extract our mineral deposits or could require us to acquire costly equipment or to incur other significant expenses in connection with our business. Moreover, new laws and regulations, amendment of existing laws and regulations, reinterpretation of legal requirements or increased governmental enforcement that relate to environmental requirements and the costs associated with complying with such requirements, could have a material adverse effect on us.

Any failure by us to comply with applicable environmental laws and regulations may cause governmental authorities to take actions that could adversely impact our operations and financial condition, including:

• issuance of sanctions, including administrative, civil and criminal penalties;

• denial, modification, or revocation of permits or other authorizations;

• imposition of injunctive obligations or other limitations on our operations, including cessation of operations; and

• requirements to perform site investigatory, remedial, or other corrective actions.

Any such regulations could require us to modify existing permits or obtain new permits, implement additional pollution control technology, curtail operations, increase significantly our operating costs, or impose additional operating restrictions among our customers that reduce demand for our products and services.

We may not be able to comply with any new or amended environmental or worker health and safety laws and regulations, and any such new or amended laws and regulations could have a material adverse effect on our operating results by requiring us to modify our operations or equipment or shut down our facilities. Additionally, our customers may not be able to comply with new or amended environmental or worker health and safety laws and regulations, which could cause our customers to curtail or cease their operations that could significantly reduce the need for our products and services. We cannot at this time reasonably estimate our costs of compliance or the timing of any costs associated with any new or amended environmental or worker health and safety laws and regulations, or any material adverse effect that any such standards will have on our customers and, consequently, on our operations.

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Silica-related legislation, health issues and litigation could have a material adverse effect on our business, reputation or results of operations.

We are subject to laws and regulations relating to human exposure to crystalline silica. Several federal and state regulatory authorities, including MSHA and OSHA, may continue to propose and implement changes in their regulations regarding workplace exposure to crystalline silica, such as permissible exposure limits and required controls and personal protective equipment. For example, in 2016, OSHA published a final rule that established a more stringent permissible exposure limit for exposure to respirable crystalline silica and provided other provisions to protect employees, such as requirements for exposure assessments, methods for controlling exposure, respiratory protection, medical surveillance, hazard communication, and recording. Compliance with most aspects of the 2016 rule relating to hydraulic fracturing was required by June 2018, and the 2016 rule further requires compliance with engineering control obligations to limit exposures to respirable crystalline silica in connection with hydraulic fracturing activities by June 2021. While compliance with the requirements of the 2016 rule may result in significant operating costs or capital expenditures, we do not expect such compliance will have a material adverse effect on our results of operations. In the event and to the extent that additional legal requirements with respect to limiting human exposure to crystalline silica are adopted in the future, we may not be able to comply with such new legal requirements, and any such new requirements could have a material adverse effect on our operating results by requiring us to modify or cease our operations.

In addition, the inhalation of respirable crystalline silica is associated with the lung disease silicosis. There is recent evidence of an association between crystalline silica exposure or silicosis and lung cancer and a possible association with other diseases, including immune system disorders such as scleroderma. These health risks have been, and may continue to be, a significant issue confronting the frac sand industry. Concerns over silicosis and other potential adverse health effects, as well as concerns regarding potential liability from the use of frac sand, may have the effect of discouraging our customers’ use of our frac sand. The actual or perceived health risks of mining, processing and handling frac sand could materially and adversely affect frac sand producers, including us, through reduced use of frac sand, the threat of product liability or employee lawsuits, increased scrutiny by federal, state and local regulatory authorities of us and our customers or reduced financing sources available to the frac sand industry.

We are subject to the MSH Act and the OSH Act, both of which impose stringent health and safety standards on numerous aspects of our operations.

Our operations are subject to the MSH Act, as amended by the Mine Improvement and New Emergency Response Act of 2006 as well as the OSH Act, including but not limited to the OSHA rule imposing more stringent requirements regarding respirable crystalline silica that was published in 2016 and most of which requirements became effective in June 2018. The MSH Act and the OSH Act impose stringent health and safety standards on numerous aspects of our operations inclusive of mineral extraction and processing operations, transportation and transloading of silica and delivery of silica sand to wellsites. These standards include, the training of personnel, operating procedures, operating and safety equipment, and other matters. Our failure to comply with such standards, or changes in such standards or the reinterpretation or more stringent enforcement thereof, could have a material adverse effect on our business and financial condition or otherwise impose significant restrictions on our ability to conduct operations.

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

In addition to the regulatory matters described above in other risk factors, we and our customers are subject to other extensive laws and regulations on matters such as plant and wildlife protection, wetlands protection, reclamation and restoration activities at mining properties after mining is completed, the discharge of materials into the environment, and the effects that mining and hydraulic fracturing have on groundwater quality and availability. Our future success depends, among other things, on the quantity and quality of our frac sand deposits, our ability to extract these deposits profitably, and our customers being able to operate their businesses as they currently do.

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

Our customers may be subject to climate change legislation or regulations restricting emissions of GHGs that could result in increased operating costs and reduced demand for the products and services we provide.

Climate change continues to attract considerable public, political and scientific attention. As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs. These efforts have included consideration by states or groupings of states of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources.

In the United States, no comprehensive climate change legislation has been implemented at the federal level, to date. However, in the absence of federal GHG-limiting legislation, the EPA has determined that GHG emissions present a danger to public health and the environment and has adopted rules under authority of the federal Clean Air Act that, among other things, directly regulate emissions of methane, a GHG, from oil and natural gas operations. EPA’s New Source Performance Standards require certain new, modified, or reconstructed facilities in the oil and natural gas sector to reduce these methane gas, and volatile organic compound emissions. Furthermore, EPA has established Potential for Significant Deterioration ("PSD") construction and Title V operating permit reviews for GHG emissions from certain large stationary sources that emit certain principal, or "criteria," pollutants. Those sources subject to PSD permitting would be required to meet "best available control technology" standards for those GHG emissions. Internationally, in April 2016, the United States joined other countries in entering into a United Nations-sponsored non-binding agreement negotiated in Paris, France ("Paris Agreement") for nations to limit their GHG emissions through individually-determined emission reduction goals every five years beginning in 2020. However, in August 2017, the U.S. State Department informed the United Nations of the United States’ intention to withdraw from this Paris Agreement, which provides for a four-year exit process beginning when it took effect in November 2016.

The adoption and implementation of any federal or state legislation or regulations or international agreements that require reporting of GHGs or otherwise restrict emissions of GHGs from our or our customers’ equipment and operations could require us or our customers to incur increased operating costs, acquire emissions allowances or comply with new regulatory or reporting requirements, including the imposition of a carbon tax. Moreover, such new legislation or regulatory programs could also materially and adversely affect demand for the oil and natural gas our customers produce, which may reduce demand for our frac sand products and services. Any one or more of these developments could have a material adverse effect on our business, financial condition and results of operations. Notwithstanding potential risks related to climate change, the International Energy Agency estimates that oil and gas will continue to represent a major share of global energy use through 2040, and other private sector studies project continued growth in demand for the next two decades. However, recent activism directed at shifting funding away from companies with energy-related assets could result in limitations or restrictions on certain sources of funding for the energy sector.

Our inability to acquire, maintain or renew financial assurances related to the reclamation and restoration of mining property could have a material adverse effect on our business, financial condition and results of operations.

We are generally obligated to restore property in accordance with regulatory standards and our approved reclamation plan following the completion of mining activities at the property. We are required under federal, state, and local laws to maintain financial assurances, such as surety bonds, to secure such obligations. The inability to acquire, maintain or renew such assurances, as required by federal, state, and local laws, could subject us to fines and penalties as well as the revocation of our operating permits. Such inability could result from a variety of factors, including:

• the lack of availability, higher expense, or unreasonable terms of such financial assurances;

• the ability of current and future financial assurance counterparties to increase required collateral; and

• the exercise by financial assurance counterparties of any rights to refuse to renew the financial assurance instruments.

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Our inability to acquire, maintain, or renew necessary financial assurances related to the reclamation and restoration of mining property could have a material adverse effect on our business, financial condition, and results of operations.

Risks Relating to our Structure

Failure to complete, or significant delays in completing, the Conversion could negatively affect the trading prices of units and the future business and financial results of the Partnership. Additionally, if the Conversion is not completed, our unitholders will continue to be required to pay taxes on their share of our taxable income whether or not they receive any cash distributions from us.

Completion of the Conversion is not assured and is subject to risks, including the risk that approval of the proposed Conversion by the unitholders is not obtained. If the Conversion is not completed, or if there are significant delays in completing the Conversion, the trading prices of units and the future business and financial results of the Partnership could be negatively affected, and the Partnership will be subject to several risks, including the following:

• negative reactions from the financial markets, including declines in the prices of common units due to the fact that current prices may reflect a market assumption that the Conversion will be completed; and

• the attention of management of the Partnership will have been diverted to the Conversion rather than its own operations and pursuit of other opportunities that could have been beneficial to the Partnership.

Additionally, if the Conversion is not completed, the Partnership will continue to be treated as a partnership for U.S. federal income tax purposes and our unitholders will continue to be required to pay any U.S. federal income taxes and, in some cases, state and local income taxes on their share of our taxable income whether or not they receive any cash distributions from us. Further, if the Partnership continues to be treated as a partnership for U.S. federal income tax purposes, the suspension or distribution of the Partnership’s cash distribution will increase the ratio of the Partnership’s allocable taxable income to cash distributions. As a result, our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income. A description of the material U.S. federal income tax consequences of the Conversion is included in the preliminary proxy statement filed by the Partnership with the SEC on February 5, 2019.

The board of directors of our general partner may modify or revoke our cash distribution policy at any time at its discretion. Our partnership agreement does not require us to pay any distributions at all.

The board of directors of our general partner has adopted a cash distribution policy pursuant to which we intend to make quarterly distributions on our units to the extent we have sufficient cash after the establishment of cash reserves and the payment of our expenses, including payments to our general partner and its affiliates. However, the board may change such policy at any time at its discretion. In January 2019, the board suspended the distribution.

In addition, our partnership agreement does not require us to pay any distributions at all. Accordingly, investors are cautioned not to place undue reliance on the permanence of such a policy in making an investment decision. Any modification or revocation of our cash distribution policy could substantially reduce or eliminate the amounts of distributions to our unitholders. The amount of distributions we make, if any, and the decision to make any distribution at all will be determined by the board of directors of our general partner, whose interests may differ from those of our common unitholders. Our general partner has limited duties to our unitholders, which may permit it to favor its own interests to the detriment of our common unitholders.

We may distribute a significant portion of our cash available for distribution to our partners, which could limit our ability to grow and make acquisitions.

We may distribute most of our cash available for distribution, which may cause our growth to proceed at a slower pace than that of businesses that reinvest their cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may impact the cash that we have available to distribute to our unitholders.

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

Our general partner intends to limit its liability under contractual arrangements between us and third parties so that the counterparties to such arrangements have recourse only against our assets, and not against our general partner or its assets. Our general partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our general partner. Our partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner’s duties, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our general partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders.

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Our partnership agreement replaces our general partner’s fiduciary duties to holders of our units.

Our partnership agreement contains provisions that eliminate and replace the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner, or otherwise free of fiduciary duties to us and our unitholders. This entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our general partner may make in its individual capacity include:

• how to allocate business opportunities among us and its affiliates;

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

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

By purchasing a common unit, a unitholder is treated as having consented to the provisions in the partnership agreement, including the provisions discussed above.

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

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

• whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is required to make such determination, or take or decline to take such other action, in good faith, and will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;

• our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith, meaning that it believed that the decision was in the best interest of our partnership;

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

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

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

(2) approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and its affiliates.

In connection with a situation involving a transaction with an affiliate or a conflict of interest, any determination by our general partner must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the conflicts committee then it will be presumed that, in making its decision, taking any action or failing to act, the board of directors of our general partner acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

Even if holders of our common units are dissatisfied, they have limited ability to remove our general partner.

If our unitholders are dissatisfied with the performance of our general partner, they have limited ability to remove our general partner. The vote of the holders of at least 66 ²/3% of all outstanding units voting together as a single class is required to remove our general partner.

Our general partner interest or the control of our general partner may be transferred to a third party without unitholder consent.

Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of our unitholders. Furthermore, our partnership agreement does not restrict the ability of the members of our general partner to transfer their respective membership interests in our general partner to a third party. The new members of our general partner would then be in a position to replace the board of directors and executive officers of our general partner with their own designees and thereby exert significant control over the decisions taken by the board of directors and executive officers of our general partner. This effectively permits a "change of control" without the vote or consent of the unitholders.

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We may issue additional units without unitholder approval, which would dilute existing unitholder ownership interests.

Our partnership agreement does not limit the number of additional limited partner interests we may issue at any time without the approval of our unitholders. The issuance of additional common units or other equity interests of equal or senior rank will have the following effects:

• our existing unitholders’ proportionate ownership interest in us will decrease;

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

• the ratio of taxable income to distributions may increase;

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

• the market price of the common units may decline.

There are no limitations in our partnership agreement on our ability to issue units ranking senior to the common units.

In accordance with Delaware law and the provisions of our partnership agreement, we may issue additional partnership interests that are senior to the common units in right of distribution, liquidation and voting. The issuance by us of units of senior rank may (i) reduce or eliminate the amount of cash available for distribution to our common unitholders; (ii) diminish the relative voting strength of the total common units outstanding as a class; or (iii) subordinate the claims of the common unitholders to our assets in the event of our liquidation.

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.

Our partnership agreement restricts unitholders’ voting rights by providing that any units held by a person or group that owns 20% or more of any class of units then outstanding, other than our general partner and its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter.

Your liability may not be limited if a court finds that unitholder action constitutes control of our business.

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law, and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some jurisdictions. You could be liable for our obligations as if you were a general partner if a court or government agency were to determine that:

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

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

Unitholders may have liability to repay distributions and in certain circumstances may be personally liable for the obligations of the partnership.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, or the Delaware Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

If we fail to maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our units.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes Oxley Act of 2002. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our units.

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The New York Stock Exchange does not require a publicly-traded partnership like us to comply with certain of its corporate governance requirements.

Our common units are listed on the NYSE under the symbol "HCLP." Because we are a publicly-traded partnership, the NYSE does not require us to have a majority of independent directors on our general partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee. Accordingly, unitholders do not have the same protections afforded to certain corporations that are subject to all of the NYSE corporate governance requirements.

Tax Risks to Common Unitholders

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service (the "IRS") were to treat us as a corporation for federal income tax purposes or we were to become subject to material additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution to you could be substantially reduced.

The anticipated after-tax economic benefit of an investment in our common units depends largely on us being treated as a partnership for federal income tax purposes.

Despite the fact that we are organized as a limited partnership under Delaware law, as a publicly traded partnership we may be treated as a corporation for federal income tax purposes unless 90% or more of our gross income in each year consists of certain identified types of "qualifying income" as defined by Section 7704 of the Internal Revenue Code (the "Qualifying Income Exception"). In addition to qualifying income, like many other publicly traded partnerships, we also generate ancillary income that may not be considered qualifying income. We have historically satisfied, and believe we currently satisfy, the Qualifying Income Exception to be treated as a partnership for federal income tax purposes. Although we monitor our level of gross income that may not be considered qualifying income closely and attempt to manage our operations to ensure compliance with the Qualifying Income Exception, during periods of weak demand and low prices for frac sand, the sale of which generates qualifying income, we may not be able to continue to meet the Qualifying Income Exception. To the extent we become aware that we may not generate or have not generated sufficient qualifying income with respect to a period, we can and would take action to preserve our treatment as a partnership for federal income tax purposes, including seeking relief from the IRS. Section 7704(e) of the Internal Revenue Code provides for the possibility of relief upon, among other things, a determination by the IRS that such failure to meet the Qualifying Income Exception was inadvertent.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate and would likely pay state income tax at varying rates. Distributions to you would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units. At the state level, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. We currently own assets and conduct business in several states that impose a margin or franchise tax. In the future, we may expand our operations. Imposition of a similar tax on us in other jurisdictions that we may expand to could substantially reduce our cash available for distribution to our unitholders.

The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes or differing interpretations, possibly applied on a retroactive basis.

The present federal income tax treatment of publicly-traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. From time to time, members of the U.S. Congress have proposed and considered substantive changes to the existing federal income tax laws that would affect publicly traded partnerships, including a prior legislative proposal that would have eliminated the Qualifying Income Exception upon which we rely for our treatment as a partnership for federal income tax purposes. In addition, the Treasury Department has issued, and in the future may issue, regulations interpreting those laws that affect publicly traded partnerships. Although there are no current legislative or administrative proposals, there can be no assurance that there will not be further changes to U.S. federal income tax laws or the Treasury Department’s interpretation of the qualifying income rules in a manner that could impact our ability to qualify as a publicly traded partnership in the future. 

Any modification to the federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the Qualifying Income Exception.  We are unable to predict whether any changes or other proposals will ultimately be enacted. Any future legislation could negatively impact the value of an investment in our common units. You are urged to consult with your own tax advisor with respect to the status of regulatory or administrative developments and proposals and their potential effect on your investment in our common units.

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Our unitholders are required to pay taxes on their share of our income even if they do not receive any cash distributions from us.

Our unitholders are required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income whether or not they receive any cash distributions from us. During periods in which the Partnership suspends or suppresses cash distributions or reinvests cash in its business, the ratio of the of the Partnership’s allocable taxable income to cash distributions will increase. As a result, our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income. Additionally, if we sell assets and use the proceeds to repay existing debt or fund capital expenditures, you may be allocated taxable income and gain resulting from the sale and our cash available for distribution would not increase. Similarly, taking advantage of opportunities to reduce our existing debt, such as debt exchanges, debt repurchases, or modifications of our existing debt could result in "cancellation of indebtedness income" being allocated to our unitholders as taxable income without any increase in our cash available for distribution.

Tax gain or loss on the disposition of our common units could be more or less than expected.

If our unitholders sell their common units, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis in those common units. Because distributions in excess of their allocable share of our net taxable income result in a decrease in their tax basis in their common units, the amount, if any, of such prior excess distributions with respect to the units they sell will, in effect, become taxable income to them if they sell such units at a price greater than their tax basis in those units, even if the price they receive is less than their original cost. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if they sell their units, they may incur a tax liability in excess of the amount of cash they receive from the sale.

A substantial portion of the amount realized from a sale of our units by our unitholders, whether or not representing gain, may be taxed as ordinary income to our unitholders due to potential recapture items, including depreciation recapture. Thus, our unitholders may recognize both ordinary income and capital loss from the sale of units if the amount realized on a sale of such units is less than such unitholder’s adjusted basis in the units. Net capital loss may only offset capital gains and, in the case of individuals, up to $3,000 of ordinary income per year. In the taxable period in which a unitholder sells its units, such unitholder may recognize ordinary income from our allocations of income and gain to such unitholder prior to the sale and from recapture items that generally cannot be offset by any capital loss recognized upon the sale of units.

Unitholders may be subject to limitation on their ability to deduct interest expense incurred by us.

In general, we are entitled to a deduction for interest paid or accrued on indebtedness properly allocable to our trade or business during our taxable year. However, under the Tax Cuts and Jobs Act, for taxable years beginning after December 31, 2017, our deduction for "business interest" is limited to the sum of our business interest income and 30% of our "adjusted taxable income." For the purposes of this limitation, our adjusted taxable income is computed without regard to any business interest expense or business interest income, and in the case of taxable years beginning before January 1, 2022, any deduction allowable for depreciation, amortization, or depletion.

Tax-exempt entities face unique tax issues from owning our common units that may result in adverse tax consequences to them.

Investment in our common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts ("IRAs") raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. With respect to taxable years beginning after December 31, 2017, subject to the proposed aggregation rules for certain similarly situated businesses or activities issued by the Treasury Department, a tax-exempt entity with more than one unrelated trade or business (including by attribution from investment in a partnership such as ours) is required to compute the unrelated business taxable income of such tax exempt entity separately with respect to each such trade or business (including for purposes of determining any net operating loss deduction). As a result, for years beginning after December 31, 2017, it may not be possible for tax-exempt entities to utilize losses from an investment in our partnership to offset unrelated business taxable income from another unrelated trade or business and vice versa. Tax-exempt entities should consult a tax advisor before investing in our common units.

Non-U.S. Unitholders will be subject to U.S. taxes and withholding with respect to their income and gain from owning our units.

Non-U.S. unitholders are generally taxed and subject to income tax filing requirements by the United States on income effectively connected with a U.S. trade or business ("effectively connected income"). Income allocated to our unitholders and any gain from the sale of our units will generally be considered to be "effectively connected" with a U.S. trade or business. As a result, distributions to a Non-U.S. unitholder will be subject to withholding at the highest applicable effective tax rate and a Non-U.S. unitholder who sells or otherwise disposes of a unit will also be subject to U.S. federal income tax on the gain realized from the sale or disposition of that unit.

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The Tax Cuts and Jobs Act imposes a withholding obligation of 10% of the amount realized upon a Non-U.S. unitholder’s sale or exchange of an interest in a partnership that is engaged in a U.S. trade or business. However, due to challenges of administering a withholding obligation applicable to open market trading and other complications, the IRS has temporarily suspended the application of this withholding rule to open market transfers of interests in publicly traded partnerships pending promulgation of regulations or other guidance that resolves the challenges. It is not clear if or when such regulations or other guidance will be issued. Non-U.S. unitholders should consult a tax advisor before investing in our common units.

If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustments directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced.

Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustments directly from us. To the extent possible under the new rules, our general partner may elect to either pay the taxes (including any applicable penalties and interest) directly to the IRS or, if we are eligible, issue a revised information statement to each unitholder and former unitholder with respect to an audited and adjusted return. Although our general partner may elect to have our unitholders and former unitholders take such audit adjustment into account and pay any resulting taxes (including applicable penalties or interest) in accordance with their interests in us during the tax year under audit, there can be no assurance that such election will be practical, permissible or effective in all circumstances. As a result, our current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own units in us during the tax year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties and interest, our cash available for distribution to our unitholders might be substantially reduced. These rules are not applicable for tax years beginning on or prior to December 31, 2017.

If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted, and the costs of any such contest will reduce our cash available for distribution to our unitholders.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. Moreover, the costs of any contest between us and the IRS will result in a reduction in our cash available for distribution to our unitholders and thus will be borne indirectly by our unitholders.

We treat each purchaser of our common units as having the same tax benefits without regard to the common units actually purchased. The IRS may challenge this treatment, which could adversely affect the value of our common units.

Because we cannot match transferors and transferees of common units, we have adopted certain methods for allocating depreciation and amortization deductions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to the use of these methods could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from any sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to a unitholder's tax returns.

We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month (the "Allocation Date"), instead of on the basis of the date a particular common unit is transferred. Similarly, we generally allocate (i) certain deductions for depreciation of capital additions, (ii) gain or loss realized on a sale or other disposition of our assets, and (iii) in the discretion of the general partner, any other extraordinary item of income, gain, loss or deduction based upon ownership on the Allocation Date. Treasury Regulations allow a similar monthly simplifying convention, but such regulations do not specifically authorize all aspects of our proration method. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss, and deduction among our unitholders.

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A unitholder whose common units are the subject of a securities loan (e.g., a loan to a "short seller" to cover a short sale of common units) may be considered as having disposed of those common units. If so, such unitholder would no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.

Because there are no specific rules governing the U.S. federal income tax consequence of loaning a partnership interest, a unitholder whose common units are the subject of a securities loan may be considered to have disposed of the loaned units. In that case, such unitholder may no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a securities loan are urged to consult a tax advisor to determine whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their common units.

We have adopted certain valuation methodologies in determining a unitholder’s allocations of income, gain, loss and deduction. The IRS may challenge these methodologies or the resulting allocations, which could adversely affect the value of our common units.

In determining the items of income, gain, loss and deduction allocable to our unitholders, we must routinely determine the fair market value of our assets. Although we may, from time to time, consult with professional appraisers regarding valuation matters, we make many fair market value estimates using a methodology based on the market value of our common units as a means to measure the fair market value of our assets. The IRS may challenge these valuation methods and the resulting allocations of income, gain, loss and deduction.

A successful IRS challenge to these methods or allocations could adversely affect the timing or amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain recognized from the sale of our common units, have a negative impact on the value of our common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

Our unitholders will likely be subject to state and local taxes and income tax return filing requirements in jurisdictions where they do not live as a result of investing in our common units.

In addition to federal income taxes, our unitholders may be subject to other taxes, including foreign, state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if they do not live in any of those jurisdictions. Our unitholders will likely be required to file foreign, state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements.

We currently own assets and conduct business in multiple states that currently impose a personal income tax on individuals, corporations, and other entities. As we make acquisitions or expand our business, we may own assets or conduct business in additional states or foreign jurisdictions that impose a personal income tax. It is our unitholders' responsibility to file all federal, foreign, state and local tax returns and pay any such taxes due in these jurisdictions. Unitholders should consult with their own tax advisors regarding the filing of such tax returns, the payment of such taxes, and the deductibility of any taxes paid.

ITEM 1B. UNRESOLVED STAFF COMMENTS

Not applicable.

ITEM 2. PROPERTIES

We lease office space for our principal executive offices in Houston, Texas and regional offices in Odessa, Texas and Canonsburg, Pennsylvania. As of December 31, 2018, we owned six production facilities located in Wisconsin and Texas, and we own all associated land. In addition, we own or operate terminal locations and lease or own railcars used to transport sand from origin to the terminal. Our PropStream last mile solution utilizes container and/or silo systems, and maintains strict proppant quality control from the mine to the blender. Substantially all of our owned assets are pledged as security under our Senior Notes and ABL Credit Facility; please see Item 7, "Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources."

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Production Facilities

Wyeville Facility

We completed construction of the Wyeville facility in June 2011 and expanded the facility in 2012. The Wyeville facility has an annual processing capacity of approximately 1,850,000 tons of frac sand per year. In July 2018, the Partnership announced its plans to expand the production capacity at its Wyeville facility by an additional 850,000 tons per year. Following the expansion, expected to be complete in the first quarter of 2019, the Wyeville facility’s annual processing capacity will increase to 2,700,000 tons of frac sand per year. During the year ended December 31, 2018, the Wyeville facility produced and delivered 2,191,214 tons of frac sand. As of December 31, 2018, the total cost of our plant and equipment was $63.3 million. The plant is in good physical condition and includes modern equipment powered by natural gas and electricity.

All of the product from the Wyeville facility is shipped by rail from approximately 32,000 feet of track that connects our facility to a Union Pacific Railroad mainline. These rail spurs and the capacity of the associated product storage silos allow us to accommodate a large number of railcars, including unit trains.

The following table summarizes certain of the key characteristics of our Wyeville facility that we believe allow us to efficiently provide our customers with high quality frac sand efficiently at competitive prices.

Facility Characteristics	Description
Site Geography	Situated on 971 contiguous acres, with on-site processing and rail loading facilities, located in Wyeville, Wisconsin.
Deposits	Sand pay zones of up to 80 feet; coarse grade mesh sizes from 20 to 100; few impurities such as clay or other contaminants.
Excavation Technique	Dredging and shallow overburden allowing for surface excavation.
Sand Processing	Sands are unconsolidated; do not require crushing.
Logistics Capabilities	On-site transportation infrastructure capable of accommodating unit trains connected to Union Pacific Railroad mainline.

Augusta Facility

We completed construction of the Augusta facility in June 2012 and expanded the facility in 2014. The Augusta facility has an annual processing capacity of approximately 2,860,000 tons of frac sand per year. The Augusta facility was temporarily idled in October 2015 until production resumed at reduced capacity levels in September 2016. The Augusta facility was again temporarily idled in January 2019. During the year ended December 31, 2018, the Augusta facility produced and delivered 1,563,733 tons of frac sand. As of December 31, 2018, the total cost of the Augusta facility and equipment was $116.0 million. The plant is in good physical condition and includes modern equipment powered by natural gas and electricity.

All of the product from the Augusta facility is shipped by rail from approximately 38,000 feet of track that connects our facility to a Union Pacific Railroad mainline. These rail spurs and the capacity of the associated product storage silos allow the accommodation of a large number of railcars, including unit trains.

The following table summarizes certain of the key characteristics of our Augusta facility that we believe allow us to efficiently provide our customers with high quality frac sand efficiently at competitive prices.

Facility Characteristics	Description
Site Geography	Situated on 1,187 contiguous acres, with on-site processing and rail loading facilities, located in Eau Claire County, Wisconsin.
Deposits	Sand pay zones of up to 80 feet; coarse grade mesh sizes from 20 to 100.
Excavation Technique	Shallow overburden allowing for surface excavation.
Sand Processing	Sands are consolidated.
Logistics Capabilities	On-site transportation infrastructure capable of accommodating unit trains connected to Union Pacific Railroad mainline.

Blair Facility

We completed construction of the Blair facility in March 2016. The Blair facility has an annual processing capacity of approximately 2,860,000 tons of frac sand per year. During the year ended December 31, 2018, the Blair facility produced and delivered 2,047,678 tons of frac sand. As of December 31, 2018, the total cost of the Blair facility and equipment was $104.1 million. The plant is in good physical condition and includes modern equipment powered by natural gas and electricity.

All of the product from the Blair facility is shipped by rail from approximately 45,000 feet of track that connects our facility to a Canadian National Railway mainline. These rail spurs and the capacity of the associated product storage silos allow us to accommodate a large number of rail cars, including unit trains.

39

The following table summarizes certain of the key characteristics of our Blair facility that we believe allow us to efficiently provide our customers with high quality frac sand efficiently at competitive prices.

Facility Characteristics	Description
Site Geography	Situated on 1,285 contiguous acres, with on-site processing and rail loading facilities, located near Blair, Wisconsin.
Deposits	Sand pay zones of up to 80 feet; coarse grade mesh sizes from 20 to 100.
Excavation Technique	Shallow overburden allowing for surface excavation.
Sand Processing	Sands are consolidated.
Logistics Capabilities	On-site transportation infrastructure capable of accommodating unit trains connected to Canadian National Railway mainline.

Whitehall Facility

We completed construction of the Whitehall facility in September 2014. The Whitehall facility has an annual processing capacity of approximately 2,860,000 tons of frac sand per year. During the year ended December 31, 2018, the Whitehall facility produced and delivered 1,351,269 tons of frac sand. The Whitehall facility was temporarily idled during the second quarter of 2016 and resumed production in March 2017. In September 2018, the Partnership temporarily idled dry plant operations at the Whitehall facility and resumed production in January 2019. As of December 31, 2018, the total cost of the Whitehall facility and equipment was $112.4 million. The plant is in good physical condition and includes modern equipment powered by natural gas and electricity.

All of the product from the Whitehall facility is shipped by rail from approximately 38,000 feet of track that connects our facility to a Canadian National Railway mainline. These rail spurs and the capacity of the associated product storage silos allow us to accommodate a large number of rail cars, including unit trains.

The following table summarizes certain of the key characteristics of our Whitehall facility that we believe allow us to efficiently provide our customers with high quality frac sand efficiently at competitive prices.

Facility Characteristics	Description
Site Geography	Situated on 1,626 contiguous acres, with on-site processing and rail loading facilities, located near Independence, Wisconsin and Whitehall, Wisconsin.
Deposits	Sand pay zones of up to 80 feet; coarse grade mesh sizes from 20 to 100.
Excavation Technique	Shallow overburden allowing for surface excavation.
Sand Processing	Sands are consolidated.
Logistics Capabilities	On-site transportation infrastructure capable of accommodating unit trains connected to Canadian National Railway mainline.

Kermit Facilities

We completed construction of the Kermit facility in July 2017 and the Kermit 2 facility in December 2018. The Kermit facilities have an annual processing capacity of approximately 6,000,000 tons of frac sand per year. During the year ended December 31, 2018, the Kermit facilities produced and delivered 3,044,923 tons of frac sand. As of December 31, 2018, the cost of the Kermit facilities and equipment was $143.1 million. The plants are in good physical condition and include modern equipment powered by natural gas and electricity.

All of the product from our Kermit facilities is delivered by truck to the wellsite from 12 on-site silos with 36,000 tons of storage capacity.

The following table summarizes certain of the key characteristics of our Kermit facilities that we believe allow us to efficiently provide our customers with high quality frac sand efficiently at competitive prices.

Facility Characteristics	Description
Site Geography	Situated on 1,226 contiguous acres, with on-site processing and truck loading facilities, located near Kermit, Texas.
Deposits	Overlain by dune sand deposits, typically 50 feet deep on average; fine 100 mesh sand.
Excavation Technique	No overburden allowing for surface excavation.
Sand Processing	Sands are unconsolidated; do not require crushing.
Logistics Capabilities	Twelve on-site silos with 36,000 tons of storage capacity and infrastructure capable of direct loading into trucks.

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Sand Reserves

Summary of Reserves

The following table provides a summary of our facilities as of December 31, 2018:

Mine/Plant Location	Owned/Leased	Area (in acres)	Proven Reserves (in thousands of tons)	Primary End Markets Served
Wyeville, WI	Owned	971	72,094	Oil and natural gas proppants
Augusta, WI	Owned	1,187	42,135	Oil and natural gas proppants
Blair, WI	Owned	1,285	112,169	Oil and natural gas proppants
Whitehall, WI	Owned	1,626	85,205	Oil and natural gas proppants
Kermit facilities, TX	Owned	1,226	100,044	Oil and natural gas proppants

"Reserves" consist of sand that can be economically extracted or produced at the time of determination based on relevant legal, economic and technical considerations. The reserve estimates referenced herein represent proven reserves, which are defined by SEC Industry Guide 7 as those for which (a) the quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; grade and/or quality are computed from the results of detailed sampling and (b) the sites for inspection, sampling and measurement are spaced so closely and the geologic character is so well defined that size, shape, depth and mineral content of reserves are well-established. The quantity and nature of the mineral reserves at our facilities are estimated by our internal geologists and mining engineers and updated periodically, with necessary adjustments for operations during the year and additions or reductions due to property acquisitions and dispositions, quality adjustments and mine plan updates. John T. Boyd has estimated our reserves as of December 31, 2018, and we intend to continue retaining third-party engineers to review our reserves on an annual basis.

To opine as to the economic viability of our reserves, John T. Boyd reviewed our financial cost and revenue per ton data at the time of the proven reserve determination. Based on its review of our cost structure and its extensive experience with similar operations, John T. Boyd concluded that it is reasonable to assume that we will operate under a similar cost structure over the remaining life of our reserves. Based on these assumptions, and taking into account possible cost increases associated with a maturing mine, John T. Boyd concluded that our current operating margins are sufficient to expect continued profitability throughout the life of our reserves.

A number of characteristics are utilized to define the quality of frac sand, such as particle shape, acid solubility, cleanliness, grain size and crush strength.  Crush strength is an indication of how well a proppant can retain its structural integrity under closure pressure and is one of the key characteristics for our customers and other purchasers of frac sand in determining whether the product will be suitable for its desired application.  For example, raw frac sand with high crush strength is suitable for use in high pressure downhole conditions that would otherwise require the use of more expensive resin-coated or ceramic proppants.

Before acquiring new reserves, we perform extensive drilling of cores and analysis and other testing of the cores to confirm the quantity and quality of the acquired reserves. Core samples are sent to leading proppant sand-testing laboratories, each of which adhere to procedures and testing methods in accordance with the American Society for Testing and Materials’ standards for testing materials.

Surface and Mineral Rights

We acquired the Wisconsin acreage from separate land owners. In each transaction, we acquired surface and mineral rights, certain of which are subject to non-participating royalty interests per ton of frac sand sold. These royalties were negotiated by us or our sponsor in connection with the acquisition of the acreage. In addition, we entered into a purchase and sale agreement to acquire certain tracts of land and specific quantities of the underlying frac sand deposits, and have the option to acquire additional mineral rights underlying the acquired land. We acquired surface rights to the Kermit, Texas acreage, which is not subject to any royalty interest on sand produced and delivered.

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Logistics

Terminals

As of December 31, 2018, we own or operate 12 terminal locations as summarized in the following table:

Location	Storage Capabilities	Railroad	Unit Train Capable
Binghamton, NY	Rail	New York Susquehanna & Western Railway	þ
Big Spring, TX	Rail	Big Spring Rail Systems
Dennison, OH (a)	Rail	Columbus and Ohio River Railroad
Driftwood, PA (a)	Rail	Buffalo and Pittsburgh Railroad
Evans, CO	Rail	Union Pacific Railroad
Kittanning, PA	Rail	Buffalo and Pittsburgh Railroad
Minerva, OH (a)	Rail/Silo	Ohio-Rail Corp.	þ
Mingo Junction, OH	Rail/Silo	Norfolk Southern	þ
Odessa, TX	Rail/Silo	Union Pacific Railroad	þ
Pecos, TX	Rail/Silo	Union Pacific Railroad	þ
Smithfield, PA	Rail/Silo	Southwest Pennsylvania Railroad	þ
Wellsboro, PA	Rail/Silo	Wellsboro & Corning Railroad	þ

(a) Terminal is idled.

As of December 31, 2018, we leased or owned 4,986 railcars used to transport sand from origin to the terminal.

PropStream

Our PropStream last mile solution utilizes container and/or silo systems, and maintains strict proppant quality control from the mine to the blender. As of December 31, 2018, we leased 2,624 containers used to transport sand from the terminal to the wellsite. As of December 31, 2018, we owned 11 FB Atlas top-fill conveyors and 28 silo systems, which includes a 6-pack of silos, a conveyor for sand from the silos to the blender hopper and the trailers used to transport the silos.

ITEM 3. LEGAL PROCEEDINGS

Legal Proceedings

We are subject to various routine legal proceedings, claims, and governmental inspections, audits or investigations arising out of our business which cover matters such as general commercial, governmental regulations, environmental, employment and other actions that are incidental to our business. Although the outcomes of these routine claims cannot be predicted with certainty, in the opinion of management, the ultimate resolution of these matters will not have a material adverse effect on our financial position or results of operations.

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 silicosis prevention program, medical surveillance, training and other components. Our safety program is designed to ensure compliance with the standards of our Occupational Health and Safety Manual and MSHA regulations. For health and safety standards, hazard and risk assessment tools and critical task specific awareness, extensive training is provided to employees. We have daily pre-task meetings and safety toolbox meetings at all of our plants with personnel and conduct monthly focus fatality hazard prevention assessments as well as quarterly corporate health and safety compliance audits. Additionally, we perform annual internal health and safety audits and conduct annual crisis management drills to test our abilities to respond to various situations. Health and safety programs are administered by our corporate health and safety department with the assistance of plant Environmental, Health and Safety coordinators.

All of our production facilities are classified as mines and are subject to regulation by MSHA under the MSH Act. The MSHA inspects our mines on a regular basis and issues various citations and orders when it believes a violation has occurred under the MSH Act. 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 Annual Report on Form 10-K.

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PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON UNITS, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF UNIT SECURITIES

Market Information

Our common units representing limited partner interests are listed on and traded on the NYSE under the symbol "HCLP." Upon completion of the Conversion, we expect to be renamed "Hi-Crush Inc.," and our common stock will be listed for trade on the NYSE under the ticker symbol "HCR."

As of December 31, 2018, there were 100,874,988 common units outstanding held by approximately 42,914 unitholders of record. Because many of our common units are held by brokers and other institutions on behalf of unitholders, we are unable to estimate the total number of unitholders represented by these record holders.

Cash Distributions to Unitholders

On October 26, 2015, we announced the decision of the board of directors of our general partner to temporarily suspend the distribution payment to common unitholders in an effort to conserve cash. On October 16, 2017, the board of directors reinstated quarterly distributions.

On January 7, 2019, we announced the decision of the board of directors of our general partner to suspend the quarterly distribution to common unitholders.

Distribution Policy

Quarterly Distributions

Within 60 days after the end of each quarter, we intend to distribute to the holders of common units on a quarterly basis a quarterly distribution per unit, to the extent we have sufficient cash after establishment of cash reserves and payment of fees and expenses. Our partnership agreement does not contain a requirement for us to pay distributions to our unitholders, and there is no guarantee that we will pay a quarterly distribution, or any distribution, on the units in any quarter.

Securities Authorized for Issuance under Equity Compensation Plans

See Item 12, "Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters" for information regarding our equity compensation plans as of December 31, 2018.

Recent Sales of Unregistered Securities

On August 1, 2018, in connection with our acquisition of FB Industries Inc., we issued 1,279,328 common units to the owners of FB Industries Inc.  The common units were issued pursuant to an exemption from registration under Section 4(a)(2) of the Securities Act of 1933, as amended because the transaction did not involve a public offering.

Purchase of Equity Securities by the Issuer and Affiliated Purchasers

None.

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ITEM 6. SELECTED FINANCIAL DATA

The Partnership's historical financial data has been recast to include our sponsor and general partner, Hi-Crush Augusta LLC ("Augusta"), Hi-Crush Blair LLC ("Blair"), Hi-Crush Whitehall LLC ("Whitehall") and PDQ Properties LLC ("PDQ Properties") for the periods leading up to their contribution into the Partnership.

(in thousands, except tons, per ton and per unit amounts)	Year Ended December 31,
	2018			2017			2016			2015			2014
Statement of Operations Data:
Revenues	$	842,840		$	602,623		$	204,430		$	339,640		$	386,547
Production costs	154,778			133,769			54,187			76,996			22,663
Logistic costs	423,196			304,579			134,121			162,629			179,516
Depreciation, depletion and amortization	38,284			29,449			17,032			16,613			12,002
Cost of goods sold	616,258			467,797			205,340			256,238			214,181
Gross profit (loss)	226,582			134,826			(910		)	83,402			172,366
Operating costs and expenses:
General and administrative	59,328			43,667			36,807			31,166			39,087
Accretion of asset retirement obligations	498			458			430			394			265
Impairments and other operating expenses	2,765			865			34,025			26,295			737
Other operating income	—			(3,554		)	—			(12,310		)	—
Income (loss) from operations	163,991			93,390			(72,172		)	37,857			132,277
Other income (expense):
Earnings from equity method investments	5,184			75			—			—			—
Interest expense	(25,347		)	(12,971		)	(20,853		)	(16,103		)	(11,040		)
Loss on extinguishment of debt	(6,233		)	(4,332		)	—			—			—
Net income (loss)	$	137,595		$	76,162		$	(93,025	)	$	21,754		$	121,237
Earnings (loss) per limited partner unit:
Limited partner units - basic	$	1.46		$	0.97		$	(1.64	)	$	0.73		$	3.09
Limited partner units - diluted	$	1.42		$	0.96		$	(1.64	)	$	0.73		$	3.00
Distributions per limited partner unit	$	1.20		$	0.35		$	—		$	1.15		$	2.40
Statement of Cash Flow Data:
Net cash provided by (used in):
Operating activities	$	237,303		$	83,975		$	(31,932	)	$	93,172		$	100,323
Investing activities	(188,137		)	(325,120		)	(52,153		)	(125,663		)	(184,183		)
Financing activities	57,367			244,026			69,168			41,676			72,081
Other Financial Data:
Adjusted EBITDA (a)	$	206,140		$	124,943		$	(19,129	)	$	81,740		$	148,476
Capital expenditures (b)	141,546			122,246			45,714			130,865			172,166
Operating Data:
Total sand sold (in tons)	10,407,296			8,938,713			4,253,746			5,003,702			4,584,811
Average price per ton sold	$	66.93		$	66.94		$	47.65		$	62.05		$	70.46
Sand produced and delivered (in tons)	10,198,814			9,067,584			4,207,044			5,008,960			4,198,656
Contribution margin per ton sold	$	25.45		$	18.38		$	3.79		$	19.99		$	40.21
Balance Sheet Data (at period end):
Cash	$	114,256		$	7,724		$	4,843		$	19,760		$	10,575
Total assets	1,433,838			1,128,229			667,328			686,709			630,403
Long-term debt	443,283			194,462			247,939			338,770			262,898
Total liabilities	626,591			302,459			296,982			415,065			335,429
Equity	807,247			825,770			370,346			271,644			294,974

(a) For more information, please read "Non-GAAP Financial Measures" below.

(b) Capital expenditures made to increase the long-term operating capacity of our asset base whether through construction or acquisitions.

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Non-GAAP Financial Measures

EBITDA and Adjusted EBITDA

We define EBITDA as net income plus depreciation, depletion and amortization and interest expense, net of interest income. We define Adjusted EBITDA as EBITDA, adjusted for any non-cash impairments of long-lived assets and goodwill, earnings (loss) from equity method investments and loss on extinguishment of debt. EBITDA and Adjusted EBITDA are not a presentation made in accordance with accounting principles generally accepted in the United States ("GAAP").

EBITDA and Adjusted EBITDA are non-GAAP supplemental financial measure that management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies, may use to assess:

• our operating performance as compared to other publicly-traded companies in the proppants industry, without regard to historical cost basis or financing methods; and

• the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.

We believe that the presentation of EBITDA and Adjusted EBITDA will provide useful information to investors in assessing our financial condition and results of operations. Our non-GAAP financial measures of EBITDA and Adjusted EBITDA should not be considered as an alternative to GAAP net income. EBITDA and Adjusted EBITDA has important limitations as an analytical tool because it excludes some but not all items that affect net income. You should not consider EBITDA or Adjusted EBITDA in isolation or as a substitute for analysis of our results as reported under GAAP. Because EBITDA and Adjusted EBITDA may be defined differently by other companies in our industry, our definition of EBITDA and Adjusted EBITDA may not be comparable to similarly titled measures of other companies, thereby diminishing its utility. EBITDA and Adjusted EBITDA are supplemental measures utilized by our management and other users of our financial statements such as investors, commercial banks, research analysts and others, to assess the financial performance of our assets without regard to financing methods, capital structure or historical cost basis.

Distributable Cash Flow

We define distributable cash flow as Adjusted EBITDA less cash paid for interest expense, including accruals and maintenance and replacement capital expenditures, including accrual for reserve replacement, plus accretion of asset retirement obligations and non-cash unit-based compensation. The Partnership's historical financial information has been recast to consolidate our sponsor and general partner, Augusta, Blair, Whitehall and PDQ Properties for the periods leading up to their contribution into the Partnership. For purposes of calculating distributable cash flow attributable to Hi-Crush Partners LP, the Partnership excludes the incremental amount of recast distributable cash flow earned during the periods prior to the contributions from our distributable cash flow. In addition, to the extent that distributable cash flow would be attributable to the holders of the incentive distribution rights during the period, such amounts are excluded from the distributable cash flow attributable to the limited partner unitholders.

We use distributable cash flow as a performance metric to compare cash generating performance of the Partnership from period to period and to compare the cash generating performance for specific periods to the cash distributions (if any) that are expected to be paid to our unitholders. Distributable cash flow will not reflect changes in working capital balances.

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The following table presents a reconciliation of EBITDA, Adjusted EBITDA and distributable cash flow to the most directly comparable GAAP financial measure, as applicable, for each of the periods indicated.

	Year Ended December 31,
(in thousands)	2018			2017			2016			2015			2014
Net income (loss)	$	137,595		$	76,162		$	(93,025	)	$	21,754		$	121,237
Depreciation and depletion expense	38,775			29,872			17,616			16,471			11,013
Amortization expense	3,374			1,681			1,682			2,620			5,186
Interest expense	25,347			12,971			20,853			16,103			11,040
EBITDA	205,091			120,686			(52,874		)	56,948			148,476
Non-cash impairments of long-lived assets and goodwill	—			—			33,745			24,792			—
Earnings from equity method investments	(5,184		)	(75		)	—			—			—
Loss on extinguishment of debt	6,233			4,332			—			—			—
Adjusted EBITDA	206,140			124,943			(19,129		)	81,740			148,476
Less: Cash interest paid, including accruals	(24,183		)	(10,950		)	(17,175		)	(12,979		)	(9,242		)
Less: Maintenance and replacement capital expenditures, including accrual for reserve replacement (a)	(18,868		)	(13,742		)	(5,680		)	(6,762		)	(5,668		)
Add: Accretion of asset retirement obligations	498			458			430			394			265
Add: Unit-based compensation	7,439			5,714			2,620			2,983			1,470
Distributable cash flow	171,026			106,423			(38,934		)	65,376			135,301
Adjusted for: Distributable cash flow attributable to assets contributed from the sponsor, prior to the period in which the contribution occurred (b)	2,796			6,573			7,758			3,450			(7,407		)
Distributable cash flow attributable to Hi-Crush Partners LP	173,822			112,996			(31,176		)	68,826			127,894
Less: Distributable cash flow attributable to holders of incentive distribution rights	(7,664		)	—			—			(1,311		)	(18,401		)
Distributable cash flow attributable to limited partner unitholders	$	166,158		$	112,996		$	(31,176	)	$	67,515		$	109,493

(a) Maintenance and replacement capital expenditures, including accrual for reserve replacement, were determined based on an estimated reserve replacement cost of $1.35 per ton produced and delivered through September 30, 2017. Effective October 1, 2017, we increased the estimated reserve replacement cost to $1.85 per ton produced and delivered, due to the addition of our Kermit facility. Effective January 1, 2019, we revised our estimated reserve replacement cost to $2.10 per ton as a result of completion of construction of the Kermit 2 facility. Such expenditures include those associated with the replacement of equipment and sand reserves, to the extent that such expenditures are made to maintain our long-term operating capacity. The amount presented does not represent an actual reserve account or requirement to spend the capital.

(b) The Partnership's historical financial information has been recast to consolidate our sponsor and general partner, Augusta, Blair, Whitehall and PDQ Properties for the periods leading up to their contribution into the Partnership. For purposes of calculating distributable cash flow attributable to Hi-Crush Partners LP, the Partnership excludes the incremental amount of recast distributable cash flow earned during the periods prior to the contributions.

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

You should read the following discussion of our historical performance and financial condition together with Part II, Item 6, "Selected Financial Data," the description of the business appearing in Part 1, Item 1, "Business," and the consolidated financial statements and the related notes in Part II, Item 8 "Financial Statements and Supplementary Data" of this Annual Report on Form 10-K. This discussion contains forward-looking statements that are based on the views and beliefs of our management, as well as assumptions and estimates made by our management. Actual results could differ materially from such forward-looking statements as a result of various risk factors, including those that may not be in the control of management. Factors that could cause or contribute to these differences include those discussed below and elsewhere in this report, particularly in Part I, Item 1A, "Risk Factors" and under "Forward-Looking Statements." All amounts are presented in thousands except acreage, tonnage and per unit data, or where otherwise noted.

Overview

We are a fully integrated, strategic provider of proppant and logistics solutions to the North American petroleum industry. We provide mine-to-wellsite logistics services that optimize proppant supply to customers in all major oil and gas basins in the United States, and own and operate multiple frac sand mining facilities and in-basin terminals. Our PropStream^® service, offering both container- and silo-based wellsite delivery and storage systems, provides the highest level of flexibility, safety and efficiency in managing the full scope and value of the proppant supply chain. 

The Partnership was formed in 2012 with the contribution of the Wyeville facility from our sponsor. In separate transactions between 2013 and 2017, we acquired all of the equity interests in the Augusta, Blair and Whitehall facilities previously owned by our sponsor. In March 2017, we acquired a 1,226-acre frac sand reserve, located near Kermit, Texas from Permian Basin Sand Company, LLC, upon which we developed our Kermit facilities.

In June 2013, we acquired D&I Silica, LLC ("D&I"), which transformed us into an integrated Northern White frac sand producer, transporter, marketer and distributor. To continue growth in our logistics services, on August 1, 2018, the Partnership completed the acquisition of FB industries Inc. ("FB Industries"), a company engaged in the engineering, design and marketing of silo-based frac sand management systems.

On October 21, 2018, the Partnership entered into a contribution agreement with our sponsor pursuant to which the Partnership acquired all of the then outstanding membership interests in the sponsor and the non-economic general partner interest in the Partnership, in exchange for 11,000,000 newly issued common units (the "Sponsor Contribution"). In connection with the acquisition, all of the outstanding incentive distribution rights representing limited partnership interests in the Partnership were canceled and extinguished and the sponsor waived any and all rights to receive contingent consideration payments from the Partnership or our subsidiaries pursuant to certain previously entered into contribution agreements to which it was a party.

Our Assets and Operations

We own and operate six production facilities located in Wisconsin and Texas. Our Wisconsin production facilities are equipped with on-site transportation infrastructure capable of accommodating unit trains connected to the Union Pacific Railroad mainline or the Canadian National Railway mainline. As of December 31, 2018, our Texas production facilities had 36,000 tons of on-site silo storage capacity and have infrastructure capable of direct loading into trucks.

The following table provides a summary of our production facilities and our proven reserves as of December 31, 2018:

Mine/Plant Name	Mine/Plant Location	In-Service Date	Area (in acres)	Annual Capacity	Proven Reserves (in thousands of tons)
Wyeville facility (a)	Wyeville, WI	June 2011	971	1,850,000	72,094
Augusta facility (b)	Augusta, WI	June 2012	1,187	2,860,000	42,135
Blair facility	Blair, WI	March 2016	1,285	2,860,000	112,169
Whitehall facility (c)	Whitehall, WI	Sept 2014	1,626	2,860,000	85,205
Kermit facilities	Kermit, TX	July 2017 / December 2018	1,226	6,000,000	100,044

(a) In July 2018, the Partnership announced its plans to expand the production capacity at its Wyeville facility by an additional 850,000 tons per year. Following the expansion, expected to be compete in the first quarter of 2019, the Wyeville facility’s annual processing capacity will increase to 2,700,000 tons of frac sand per year.

(b) The Augusta facility was temporarily idled in January 2019.

(c) In September 2018, the Partnership temporarily idled dry plant operations at the Whitehall facility and resumed production in January 2019.

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According to John T. Boyd Company ("John T. Boyd"), our proven reserves at our facilities consist of frac sand exceeding American Petroleum Institute ("API") specifications. Analysis of sand at our facilities by independent third-party testing companies indicates that they demonstrate characteristics exceeding API specifications with regard to crush strength, turbidity and roundness and sphericity. Based on third-party reserve reports by John T. Boyd, as of December 31, 2018, we have an implied average reserve life of 25 years, assuming production at the current rated capacity of 16,430,000 tons of frac sand per year.

As of December 31, 2018, we own or operate 12 terminal locations throughout Pennsylvania, Ohio, Texas, Colorado and New York, of which three are idled and seven are capable of accommodating unit trains. Our terminals include approximately 114,000 tons of rail storage capacity and approximately 140,000 tons of silo storage capacity. We seek to increase the number of terminals we operate and expand our geographic footprint, allowing us to further enhance our customer service and putting us in a stronger position to take advantage of opportunistic short-term pricing agreements.

Our terminals are strategically located to provide access to Class I railroads, which enables us to cost effectively ship product from our production facilities in Wisconsin. As of December 31, 2018, we leased or owned 4,986 railcars used to transport sand from origin to destination and managed a fleet of 2,169 additional railcars dedicated to our facilities by our customers or the Class I railroads.

In September 2016, the Partnership entered into an agreement to become a member of Proppant Express Investments, LLC ("PropX"), which was established to develop critical last mile logistics equipment for the proppant industry. In October 2016, the Partnership began providing to customers its PropStream integrated logistics service, which involves loading frac sand at in-basin terminals into PropX containers before being transported by truck to the wellsite. At the wellsite, we believe the PropX proprietary conveyor system, PropBeast^®, significantly reduces noise and dust emissions due to its fully enclosed environment. As of December 31, 2018, we owned 34 PropBeast conveyors and leased 2,624 containers from PropX.

On August 1, 2018, the Partnership completed the acquisition of FB industries, a company engaged in the engineering, design and marketing of silo-based frac sand management systems. As of December 31, 2018, we owned 11 FB Atlas top-fill conveyors and 28 silo systems, which includes a 6-pack of silos, a conveyor for sand from the silos to the blender hopper and the trailers use to transport the silos.

How We Generate Revenue

We generate revenue by excavating, processing and delivering frac sand and providing related services. A substantial portion of our frac sand is sold to customers with whom we have long-term contracts which have current terms expiring between 2020 and 2024. Each contract defines the minimum volume of frac sand that the customer is required to purchase, the volume that we are required to make available, the technical specifications of the product and the price per ton. During 2016, we provided contract customers with temporary market pricing arrangements at a discount to certain contracted pricing levels. In 2017, we began to revise the pricing structure in our contracts for sand sourced from our Wisconsin facilities to be periodically negotiated pricing generally reflective of market conditions and prices. Our contracts for sand sourced from our Kermit facilities are generally fixed price for the life of the contract. We also sell our frac sand on the spot market at prices and other terms determined by the existing market conditions as well as the specific requirements of the customer. Delivery of sand to our customers may occur at the production facility, rail origin, terminal or wellsite.

We generate other revenues through the performance of our PropStream logistics service, which includes transportation, equipment rental, and labor services, and through activities performed at our in-basin terminals, including transloading sand for counterparties, and lease of storage space and other services performed on behalf of our customers.

A substantial portion of our logistics services are provided to customers with whom we have long-term agreements as defined in master services agreements ("MSA") and related work orders.  The MSA typically outlines the general terms and conditions for work performed by us relating to invoicing, insurance, indemnity, taxes and similar terms.  The work orders typically define the commercial terms including the type of equipment and services to be provided, with pricing that is generally determined on a job-by-job basis due the variability in the specific requirements of each wellsite.  The MSA and related work orders are typically separate from any sand supply contract we may have with the same customer.

We may, from time to time, sell silo systems and related equipment to third parties at negotiated prices for the specific equipment.

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Costs of Conducting Our Business

Production Costs

The principal expenses involved in production of raw frac sand are excavation costs, plant operating costs, labor, utilities, maintenance and royalties. We have a contract with a third party to excavate raw frac sand, deliver the raw frac sand to our wet processing facilities and move the sand from our washed sand stockpiles to our dry plants. We pay a fixed price per ton excavated and delivered without regard to the amount of sand excavated that meets API specifications. Accordingly, we incur excavation costs with respect to the excavation of sand and other materials from which we ultimately do not derive revenue (rejected materials), and for sand which is still to be processed through the dry plant and not yet sold. However, the ratio of rejected materials to total amounts excavated has been, and we believe will continue to be, in line with our expectations, given the extensive core sampling and other testing we undertook at our facilities.

Labor costs associated with employees at our processing facilities represent the most significant cost of converting raw frac sand to finished product. We incur utility costs in connection with the operation of our processing facilities, primarily electricity and natural gas, which are both susceptible to price fluctuations. Our facilities require periodic scheduled maintenance to ensure efficient operation and to minimize downtime. Excavation, labor, utilities and other costs of production are capitalized as a component of inventory and are reflected in cost of goods sold when inventory is sold.

We pay royalties to third parties at our Wisconsin facilities at various rates, as defined in the individual royalty agreements. We currently pay an aggregate rate up to $5.15 per ton of sand excavated, processed and sold from our Wisconsin facilities, delivered to and paid for by our customers. No royalties are due on the sand extracted, processed and sold from our Kermit facilities.

We may, from time to time, purchase sand and other proppant through a long-term supply agreement with a third party at a specified price per ton and also through the spot market.

Logistics Costs

The principal expenses involved in distribution of processed sand are rail freight and fuel surcharges, railcar lease expense, and trucking charges. These logistics costs are capitalized as a component of finished goods inventory held in-basin and are reflected in cost of goods sold when the inventory is eventually sold in-basin or at the wellsite. Other logistics cost components, including transload fees, storage fees, and terminal operational costs, such as labor and facility rent, are charged to costs of goods sold in the period in which they are incurred. We utilize multiple railroads to transport our sand and such transportation costs are typically negotiated through long-term working relationships.

The principal expenses involved in delivering sand to the wellsite are costs associated with third party trucking vendors, container rent, labor and other operating expenses associated with handling the product at the wellsite. These logistics costs are charged to costs of goods sold in the period in which they are incurred.

The principal expenses associated with the sale of silo systems and related equipment is the cost of the equipment generally manufactured by third parties, as well as testing and delivery charges to the location specified by the customer. These expenses are capitalized into equipment inventory and charged to cost of goods sold when delivery is completed to the customer.

General and Administrative Costs

We incur general and administrative costs related to our corporate operations, which includes our corporate office and facilities rent, administrative personnel payroll related expenses, professional fees, insurance, stock-based compensation and depreciation and amortization expenses.

How We Evaluate Our Operations

We utilize various financial and operational measures to evaluate our operations. Management measures the performance of the Partnership through performance indicators, including gross profit, contribution margin, earnings before interest, taxes, depreciation and amortization ("EBITDA"), Adjusted EBITDA and distributable cash flow.

Gross Profit and Contribution Margin

We use gross profit, which we define as revenues less costs of goods sold and depreciation, depletion and amortization, to measure our financial performance. We believe gross profit is a meaningful measure because it provides a measure of profitability and operating performance based on the historical cost basis of our assets.

We use contribution margin, which we define as total revenues less costs of goods sold excluding depreciation, depletion and amortization, to measure our financial and operating performance. Contribution margin excludes other operating expenses and income, including costs not directly associated with the operations of our business such as accounting, human resources, information technology, legal, sales and other administrative activities.  We believe contribution margin is a meaningful measure because it provides an operating and financial measure of our ability to generate margin in excess of our operating cost base.  

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As a result, contribution margin, contribution margin per ton sold, sales volumes, sales price per ton sold and gross profit are key metrics used by management to evaluate our results of operations.

EBITDA, Adjusted EBITDA and Distributable Cash Flow

We view EBITDA and Adjusted EBITDA as important indicators of performance. We define EBITDA as net income (loss) plus depreciation, depletion and amortization and interest expense, net of interest income. We define Adjusted EBITDA as EBITDA, adjusted for any non-cash impairments of long-lived assets and goodwill, earnings (loss) from equity method investments and loss on extinguishment of debt. We define distributable cash flow as Adjusted EBITDA less cash paid for interest expense, including accruals and maintenance and replacement capital expenditures, including accrual for reserve replacement, plus accretion of asset retirement obligations and non-cash unit-based compensation. We use distributable cash flow as a performance metric to compare cash performance of the Partnership from period to period and to compare the cash generating performance for specific periods to the cash distributions (if any) that are expected to be paid to our unitholders. Distributable cash flow will not reflect changes in working capital balances. EBITDA and Adjusted EBITDA are supplemental measures utilized by our management and other users of our financial statements, such as investors, commercial banks, research analysts and others, to assess the financial performance of our assets without regard to financing methods, capital structure or historical cost basis.

Note Regarding Non-GAAP Financial Measures

EBITDA, Adjusted EBITDA and distributable cash flow are not financial measures presented in accordance with GAAP. We believe that the presentation of these non-GAAP financial measures will provide useful information to investors in assessing our financial condition and results of operations. Our non-GAAP financial measures should not be considered as alternatives to the most directly comparable GAAP financial measure. Each of these non-GAAP financial measures has important limitations as analytical tools because they exclude some but not all items that affect the most directly comparable GAAP financial measures. You should not consider EBITDA, Adjusted EBITDA or distributable cash flow in isolation or as substitutes for analysis of our results as reported under GAAP. Because EBITDA, Adjusted EBITDA and distributable cash flow may be defined differently by other companies in our industry, our definitions of these non-GAAP financial measures may not be comparable to similarly titled measures of other companies, thereby diminishing their utility. Please read Item 6, "Selected Financial Data—Non-GAAP Financial Measures."

Basis of Presentation

The following discussion of our historical performance and financial condition is derived from the historical financial statements.

Factors Impacting Comparability of Our Financial Results

Our historical results of operations and cash flows are not indicative of results of operations and cash flows to be expected in the future, principally for the following reasons:

• On August 1, 2018, we completed the acquisition of FB Industries Inc. On August 1, 2018, the Partnership purchased FB Industries, a company engaged in the engineering, design and marketing of silo-based frac sand management systems. Accordingly, our financial statements reflect increased sales of equipment, costs of goods sold, related operating costs and general and administrative expenses associated with the FB Industries operations.

• We commenced operations at our Kermit production facility on July 31, 2017. The Kermit facility commenced operations and sales of frac sand during the third quarter of 2017, resulting in an increase in volumes produced and delivered during 2018 and 2017 as compared to 2016.

• Our Whitehall production facility was temporarily idled from the second quarter of 2016 through March 2017. The Whitehall facility was temporarily idled during the second quarter of 2016 and resumed production in March 2017, resulting in an increase in volumes produced and delivered during 2017 as compared to 2016. In September 2018, the Partnership temporarily idled dry plant operations at the Whitehall facility and resumed production in January 2019.

• Our Augusta production facility was temporarily idled from October 2015 through September 2016. In October 2015, we temporarily idled our Augusta facility until production resumed at reduced capacity levels in September 2016. We resumed production at rates near full capacity in April 2017, resulting in an increase in volumes produced and delivered during 2018 and 2017 as compared to 2016.

• During the fourth quarter of 2016, we launched PropStream, our integrated logistics service, which delivers proppant into the blender at the wellsite. Accordingly, our financial statements reflect an increase in frac sand sales, other service revenues and logistics costs during 2018 and 2017 as compared to 2016.

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• We refinanced our Prior Revolving Credit Agreement and Prior Term Loan Credit Facility in December 2017. In December 2017, the Partnership refinanced its senior secured revolving credit agreement (the "Prior Revolving Credit Agreement") and senior secured term loan credit facility (the "Prior Term Loan Credit Facility") by entering into a second amended and restated credit agreement (the "Revolving Credit Agreement") and a senior secured term loan credit facility (the "Term Loan Credit Facility"). In connection with the refinancing, the Partnership recognized a $4,332 loss on extinguishment of debt, which represents the write-off of all remaining unamortized debt issuance costs and unamortized original issuance discount.

• We terminated our Revolving Credit Agreement and Term Loan Credit Facility in August 2018. On August 1, 2018, the Partnership completed the private placement of $450,000 aggregate principal amount of its 9.50% senior unsecured notes due 2026 (the "Senior Notes") and entered into a senior secured revolving credit facility (the "ABL Credit Facility"). Upon closing on the Senior Notes and ABL Credit Facility, the Partnership terminated its Revolving Credit Agreement and Term Loan Credit Facility. In connection with the terminations, the Partnership recognized a $6,233 loss on extinguishment of debt, which represents the write-off of all remaining unamortized debt issuance costs and unamortized original issuance discount.

• We impaired our goodwill during the first quarter of 2016.  During the year ended December 31, 2016, we completed an impairment assessment of our goodwill. As a result of the assessment, we estimated the fair value of our goodwill and determined that it was less than its carrying value, resulting in an impairment of $33,745.

• We incurred bad debt expense in connection with a customer’s bankruptcy filing. We incurred bad debt expense of $8,236 during the first quarter of 2016, principally as a result of a spot customer filing for bankruptcy.

Market Conditions

Exploration and production activity increased throughout 2017 and continued to do so in 2018, as demonstrated by the growth in the reported Baker Hughes U.S. land rig count from a low average of 380 rigs in May 2016 to 1,056 rigs as of December 28, 2018, reflecting an increase of 16% since the end of 2017. Well completion activity has, for the most part, similarly increased over the same periods, and, when coupled with continued growth in frac sand usage per well, has resulted in an increased positive influence on demand for raw frac sand. The industry currently estimates 2018 total annual demand was approximately 110 million tons of frac sand, up significantly from 2017 and historical levels. However, demand slowed significantly in the latter half of 2018 as well completion activity declined, which we believe is due to early exhaustion of exploration and production capex budgets and pipeline capacity constraints impacting E&Ps’ ability to move produced hydrocarbons from production areas to demand centers. While greater demand is forecasted for 2019 than 2018, the pace and timing of the growth remains uncertain. While stated frac sand capacity may exceed near-term demand, available industry capacity is constrained due to several factors, including availability of the grades of frac sand that are most in demand in certain regions or well completion environments, general operating conditions and normal downtime, and logistics constraints. In response to growing demand for U.S. frac sand, the industry has developed additional capacity which will continue to ramp up into 2019, with the majority of this development in the Permian Basin.

In August of 2018, well completion activity slowed significantly as many E&Ps reduced spending or had reached their budgeted spending levels more quickly than anticipated as well completion efficiencies continued to improve through the first half of 2018. Within the Permian Basin, concerns around pipeline takeaway capacity for transporting crude oil out of the basin also may have impacted E&Ps’ decisions to reduce spending for the remainder of 2018. Additionally, with the completion of construction and start-up of operations at several Permian mines during 2018, In-Basin supply has become more available. The advent of sand supply available closer to the wellsite in the Permian Basin, and to a lesser extent in the Eagle Ford, Haynesville and Mid-Con basins, has resulted in a rapid shift in consumption in the latter part of 2018 from Northern White sand to In-Basin sand supply. The onset of reduced activity has caused frac sand demand growth to lag the increase in supply, and has resulted in a significant reduction in pricing, particularly for Northern White sand, that is impacting sand pricing in all basins. These factors resulted in declines in pricing of 10 percent or more in the latter part of 2018. In response to the price decline, we and many of our competitors have reduced available capacity through the temporary idling of facilities. We anticipate pricing weakness will continue in the first quarter of 2019, but expect pricing to stabilize and improve somewhat as capacity comes off the market and frac sand demand increases as expected in 2019.

We believe there will be continued demand for Northern White frac sand within the Permian Basin as completion activity within that basin increases due to customer preferences and other factors. However, we believe a large portion of Northern White frac sand which previously supplied the Permian Basin will be displaced due to continued adoption of locally-produced sand. These Northern White volumes may be reallocated into other major basins around the country where they are most cost-effectively delivered via rail, barge or other modes of transportation, and which do not have the same readily available production of In-Basin sand. However, over time we believe frac sand facilities producing Northern White at a higher cost are likely to be idled or permanently shut down due to increased competition within these regions resulting in realized sales pricing below the level at which such facilities can profitably operate. At this time it is not possible to determine which facilities will be idled or shut down, or the exact timeframe in which such actions would be taken.

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We anticipate improving activity in 2019 as E&Ps focus a larger share of their capital budgets on completions and additional takeaway capacity in the Permian Basin becomes available, but the pace of improvement remains uncertain. Supply and demand dynamics for frac sand should also improve as more capacity is shut down, construction of new In-Basin supply slows, and demand fundamentals continue to strengthen. Overall, some headwinds may prove more persistent than previously anticipated, continuing the challenging environment for Northern White sand. Additionally, an increase in the number of drilled but uncompleted wells represent pent up demand for completions services and frac sand that will provide further support for overall demand in 2019 and beyond, regardless of rig count activity.

The following table presents sales, volume and pricing comparisons for the fourth quarter of 2018, as compared to the third quarter of 2018:

	Three Months Ended
	December 31,		September 30,					Percentage
	2018		2018		Change			Change
Revenues generated from the sale of frac sand (in thousands)	$	114,831	$	177,585	$	(62,754	)	(35	)%
Tons sold	1,976,805		2,775,360		(798,555		)	(29	)%
Average price per ton sold	$	58	$	64	$	(6	)	(9	)%

Revenues generated from the sale of frac sand declined primarily due to the overall sequential decrease in sales volumes, more specifically a decline in the sales volumes of Northern White sand due to both the influx of available supply from in-basin production facilities and a slowing of well completion activity. A decline in overall average sales price was driven by both a higher percentage of volumes sold from our in-basin Kermit facility, which has a lower average price than in-basin Northern White sand sold at the terminal or wellsite, coupled with reduced pricing of Kermit sand due to the aforementioned increase in In-Basin sand supply.

Results of Operations

The following table presents consolidated revenues and expenses for the periods indicated. This information is derived from the consolidated statements of operations for the years ended December 31, 2018, 2017 and 2016.

	Year Ended December 31,
	2018			2017			2016
Revenues	$	842,840		$	602,623		$	204,430
Costs of goods sold
Production costs	154,778			133,769			54,187
Logistic costs	423,196			304,579			134,121
Depreciation, depletion and amortization	38,284			29,449			17,032
Gross profit (loss)	226,582			134,826			(910		)
Operating costs and expenses	62,591			41,436			71,262
Income (loss) from operations	163,991			93,390			(72,172		)
Other income (expense)
Earnings from equity investment methods	5,184			75			—
Interest expense	(25,347		)	(12,971		)	(20,853		)
Loss on extinguishment of debt	(6,233		)	(4,332		)	—
Net income (loss)	$	137,595		$	76,162		$	(93,025	)

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Year Ended December 31, 2018 Compared to Year Ended December 31, 2017

Revenues

The following table presents sales, volume and pricing comparisons for the year ended December 31, 2018, as compared to the year ended December 31, 2017:

	Year Ended December 31,						Percentage
	2018		2017		Change		Change
Revenues generated from the sale of frac sand (in thousands)	$	696,603	$	598,355	$	98,248	16	%
Tons sold	10,407,296		8,938,713		1,468,583		16	%
Average price per ton sold	$	67	$	67	$	—	—	%

Revenues generated from the sale of frac sand were $696,603 and $598,355 for the years ended December 31, 2018 and 2017, respectively, during which we sold 10,407,296 and 8,938,713 tons of frac sand, respectively. The volume increase is primarily the result of improved year over year market conditions, as well as increased production capacity following the commencement of operations at the Kermit facility in the third quarter of 2017. Average sales price per ton was $67 for each of the years ended December 31, 2018 and 2017. While average sales pricing was generally increasing throughout the entirety of 2017, average sales pricing in 2018 traced a bell-shaped curve, with prices rapidly increasing during the first half of 2018 as the industry struggled to deliver enough volumes to keep pace with surging demand, followed by a steep decline in pricing during the second half of 2018 due to a large increase in supply from newly constructed in-basin production facilities and a slowdown in completions activity driven by exploration and production budget exhaustion and pipeline capacity constraints.

Other revenues related to PropStream integrated logistics services and activities performed at our in-basin terminals, including transloading, railcar storage, silo storage and other services was $146,237 and $4,268 for the years ended December 31, 2018 and 2017, respectively. The increase in other revenues is a direct result of increased activity levels at our terminals and year over year increased use of our PropStream integrated logistics services.

Costs of Goods Sold – Production Costs

We incurred production costs of $154,778 and $133,769 for the years ended December 31, 2018 and 2017, respectively. The increase in production costs for the year ended December 31, 2018 was primarily attributable to an increase in volumes being produced and delivered across our four Wisconsin production facilities compared to the same period in 2017 as well as a full period of operations at our Kermit facility which commenced operations in the third quarter of 2017. For the years ended December 31, 2018 and 2017, we purchased $16,724 and $10,184, respectively, of sand and other proppants from third-party suppliers.

Costs of Goods Sold – Logistics Costs

We incurred logistics costs of $423,196 and $304,579 for the years ended December 31, 2018 and 2017, respectively, reflecting a significant increase in volumes handled and sold via our PropStream logistics services at the wellsite, as well as a slight year-over-year increase in Northern White volumes sold via our in-basin terminal network.

Costs of Goods Sold – Depreciation, Depletion and Amortization of Intangible Assets

For the years ended December 31, 2018 and 2017, we incurred $38,284 and $29,449, respectively, of depreciation, depletion and amortization expense, generally using the units-of-production method of depreciation. The increase was primarily attributable to depreciation of our Kermit facility which commenced operations in the third quarter of 2017 and increased amortization expense associated with assets acquired from FB Industries.

Gross Profit

Gross profit was $226,582 and $134,826 for the years ended December 31, 2018 and 2017, respectively. Gross profit percentage increased to 26.9% for the year ended December 31, 2018 from 22.4% for the year ended December 31, 2017. The increase was primarily driven by increased prices and volumes during 2018 compared to 2017.

Operating Costs and Expenses

For the year ended December 31, 2018, we incurred total operating costs and expenses of $62,591 primarily attributable to general and administrative expenses of $59,328. General and administrative expenses for the year ended December 31, 2018 included $5,595 of non-recurring business development and legal costs associated with the Sponsor Contribution and lease termination costs associated with the relocation of our corporate offices. In addition, during the year ended December 31, 2018, the Partnership incurred $1,000 of other operating expenses related to the settlement of a contract dispute.

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For the year ended December 31, 2017, we incurred total operating costs and expenses of $41,436 primarily attributable to general and administrative expenses of $43,667 and impairments and other expenses of $865, offset by $3,554 of other operating income related to a contract dispute that was subsequently resolved. During the year ended December 31, 2017, the Partnership incurred non-recurring legal, professional and marketing costs of $3,261 associated with the Whitehall Contribution, the development of our Kermit facility and Pecos terminal and other business development activities.

The increase in general and administrative expense for 2018 compared to 2017 was generally attributable to increased headcount necessitated due to growth of the business and increased property tax and insurance costs from an expanded asset base.

Earnings from Equity Method Investments

During the years ended December 31, 2018 and 2017, the Partnership recognized earnings of $5,184 and $75, respectively, from its equity method investments, comprised primarily of our investment in PropX. PropX earnings in 2018 were driven by increased rentals of containers and sales of conveyors.

Interest Expense

Interest expense was $25,347 and $12,971 for the years ended December 31, 2018 and 2017, respectively, principally associated with the interest on our term loan and Senior Notes. The increase in interest expense during the 2018 period was primarily driven by the issuance of $450,000 of 9.50% Senior Notes in August 2018.

Loss on Extinguishment of Debt

During the year ended December 31, 2018, the Partnership terminated our Revolving Credit Agreement and our Term Loan Credit Facility. In connection with the terminations, the Partnership recognized a $6,233 loss on extinguishment of debt, which represents the write-off of all remaining unamortized debt issuance costs and unamortized original issuance discount.

During the year ended December 31, 2017, the Partnership replaced our Prior Revolving Credit Agreement and our Prior Term Loan Credit Facility by entering into a new Revolving Credit Agreement and Term Loan Credit Facility. In connection with the refinancing, the Partnership recognized a $4,332 loss on extinguishment of debt, which represents the write-off of all remaining unamortized debt issuance costs and unamortized original issuance discount.

Net Income

Net income was $137,595 and $76,162 for the years ended December 31, 2018 and 2017, respectively.

Year Ended December 31, 2017 Compared to Year Ended December 31, 2016

Revenues

The following table presents sales, volume and pricing comparisons for the year ended December 31, 2017, as compared to the year ended December 31, 2016:

	Year Ended December 31,						Percentage
	2017		2016		Change		Change
Revenues generated from the sale of frac sand (in thousands)	$	598,355	$	202,709	$	395,646	195	%
Tons sold	8,938,713		4,253,746		4,684,967		110	%
Average price per ton sold	$	67	$	48	$	19	40	%

Revenues generated from the sale of frac sand were $598,355 and $202,709 for the years ended December 31, 2017 and 2016, respectively, during which we sold 8,938,713 and 4,253,746 tons of frac sand, respectively. The volume increase is a result of improving market conditions, which necessitated the resumption of operations at the Whitehall facility in March 2017 and the commencement of operations at the Kermit facility in July 2017. Average sales price per ton was $67 and $48 for the years ended December 31, 2017 and 2016, respectively. After providing discounted pricing for contract customers for most of 2016, average sales prices began rising late in the year and were climbing throughout the entirety of 2017 due to improved market conditions which resulted in demand outstripping available supply in several regions for a significant portion of the year.

Other revenues related to PropStream services, transload and terminaling, railcar storage, silo storage and other services was $4,268 and $1,721 for the years ended December 31, 2017 and 2016, respectively.

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Costs of Goods Sold – Production Costs

We incurred production costs of $133,769 and $54,187 for the years ended December 31, 2017 and 2016, respectively. The increase in production costs for the year ended December 31, 2017 was primarily attributable to an increase in volumes being produced and delivered from our production facilities compared to 2016, coupled with having all five of our production facilities in operation during the majority of 2017. In addition, during the year ended December 31, 2017, we recognized a non-cash charge of $2,308 related to the use of coarse material from inventory to augment our reclamation process. For the year ended December 31, 2017, we purchased $10,184 of sand from other suppliers. During the year ended December 31, 2016, our production facilities were able to supply all of our sand requirements and we did not purchase any sand from third-parties.

Costs of Goods Sold – Logistics Costs

We incurred logistics costs of $304,579 and $134,121 for the years ended December 31, 2017 and 2016, respectively, reflecting an increase in volumes sold in-basin via our terminal network and at the wellsite. During the year ended December 31, 2017, we incurred $794 of costs associated with the storage of idled railcars and one-time costs to remove our remaining railcars out of storage and back into service, as compared to $1,620 for storage of idled railcars in 2016.

Costs of Goods Sold – Depreciation, Depletion and Amortization of Intangible Assets

For the years ended December 31, 2017 and 2016, we incurred $29,449 and $17,032, respectively, of depreciation, depletion and amortization expense. The increase was driven by an increase in mining activity at our Wisconsin production facilities, coupled with an increased asset base in 2017, including the commencement of operations at the Kermit facility.

Gross Profit (Loss)

Gross profit was $134,826 for the year ended December 31, 2017, compared to gross loss of $910 for the year ended December 31, 2016. Gross profit (loss) percentage increased to 22.4% for the year ended December 31, 2017 from (0.4)% for the year ended December 31, 2016. The increase was primarily driven by increased prices and volumes in 2017.

Operating Costs and Expenses

For the year ended December 31, 2017, we incurred total operating costs and expenses of $41,436 primarily attributable to general and administrative expenses of $43,667 and impairments and other expenses of $865, offset by $3,554 of other operating income related to a contract dispute that was subsequently resolved. During the year ended December 31, 2017, the Partnership incurred non-recurring legal, professional and marketing costs of $3,261 associated with the Whitehall Contribution, the development of our Kermit facility and Pecos terminal and other business development activities.

For the year ended December 31, 2016, we incurred total operating costs and expenses of $71,262, which included general and administrative expenses of $36,807 and impairments and other expenses of $34,025 primarily related to the impairment of goodwill. General and administrative expenses for the year ended December 31, 2016 also included $1,257 in transaction costs associated with the Blair Contribution and other business development activities and $8,236 of bad debt expense associated primarily with a spot customer filing for bankruptcy.

Earnings from Equity Method Investments

During the year ended December 31, 2017, the Partnership recognized earnings of $75 from its equity method investment in PropX representing its proportionate share of PropX's operating results during the year. The earnings were driven by increased rentals of containers and sales of conveyors, partially offset by the initial start-up and legal costs incurred since the formation of the joint venture in September 2016.

Interest Expense

Interest expense was $12,971 and $20,853 for the years ended December 31, 2017 and 2016, respectively, principally associated with the interest on our term loan. The decrease in interest expense during the 2017 period was primarily driven by the payment in full of the outstanding balance on our revolver in the second quarter of 2016, coupled with capitalized interest on major construction projects completed in 2017.

Loss on Extinguishment of Debt

During the year ended December 31, 2017, the Partnership replaced our Prior Revolving Credit Agreement and our Prior Term Loan Credit Facility by entering into a new Revolving Credit Agreement and Term Loan Credit Facility. In connection with the refinancing, the Partnership recognized a $4,332 loss on extinguishment of debt, which represents the write-off of all remaining unamortized debt issuance costs and unamortized original issuance discount.

Net Income (Loss)

Net income was $76,162 for the year ended December 31, 2017, compared to net loss of $93,025 for the year ended December 31, 2016.

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Liquidity and Capital Resources

Overview

We expect our principal sources of liquidity will be available cash, cash generated by our operations, and if needed, supplemented by borrowings under our ABL Credit Facility, as available. We believe that cash from these sources will be sufficient to meet our short-term working capital requirements and long-term capital expenditure requirements. As of February 14, 2019, our sources of liquidity consisted of $61,467 of available cash and $58,721 pursuant to available borrowings under our ABL Credit Facility ($79,788, net of $21,067 letter of credit commitments).

We may also sell, from time to time, common units representing limited partner interests in the Partnership up to an aggregate gross sales price of $50,000 under an equity distribution program. Our general partner is also authorized to issue an unlimited number of units without the approval of existing limited partner unitholders.

We expect that our future principal uses of cash will be for working capital, capital expenditures, funding debt service obligations, making distributions to our unitholders and any repurchases of common units.

Senior Notes and ABL Credit Facility

As of February 14, 2019, we have $450,000 of 9.50% Senior Notes which mature on August 1, 2026 and had $58,721 of undrawn borrowing capacity ($79,788, net of $21,067 letter of credit commitments) under our ABL Credit Facility. The ABL Credit Facility contains customary representations and warranties and customary affirmative and negative covenants, including limits or restrictions on the Partnership’s ability to incur liens, incur indebtedness, make certain restricted payments, merge or consolidate, and dispose of assets. As of December 31, 2018, we are in compliance with the covenants contained in the ABL Credit Facility.

Borrowings under our Senior Notes and ABL Credit Facility are secured by substantially all of our assets. In addition, our subsidiaries have guaranteed our obligations under both credit agreements and have granted the lenders security interests in substantially all our their respective assets. For additional information regarding our Senior Notes and ABL Credit Facility, see Note 10 of the Notes to Consolidated Financial Statements included in Item 15. "Exhibits, Financial Statement Schedules" of this Annual Report on Form 10-K.

Credit Ratings

As of February 14, 2019, the credit rating of the Partnership’s Senior Notes was B3 from Moody’s Investors Service Inc. and B- from Standard and Poor’s.

The credit ratings of the Partnership’s Senior Notes reflect only the view of a rating agency and should not be interpreted as a recommendation to buy, sell or hold any of our securities.  A credit rating can be revised upward or downward or withdrawn at any time by a rating agency, if it determines that circumstances warrant such a change.  A credit rating from one rating agency should be evaluated independently of credit ratings from other rating agencies.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements that have or are reasonably likely to have a material effect on our current or future financial condition, changes in financial condition, sales, expenses, results of operations, liquidity, capital expenditures or capital resources.

The Partnership has long-term operating leases for railcars and equipment used at its terminal sites, some of which are also under long-term lease agreements with various railroads.

Equity Distribution Agreement

On January 4, 2017, the Partnership entered into an equity distribution program with certain financial institutions (each, a "Manager") under which we may sell, from time to time, through or to the Managers, common units representing limited partner interests in the Partnership up to an aggregate gross sales price of $50,000. As of February 14, 2019, the Partnership had not issued any common units under this equity distribution program.

Distributions

On January 7, 2019, we announced the decision of the board of directors of our general partner to suspend the quarterly distribution to common unitholders.

Unit Buyback Program

On October 17, 2017, the Partnership announced that the board of directors of our general partner approved a unit buyback program of up to $100,000. The unit repurchase program does not obligate the Partnership to repurchase any specific dollar amount or number of units and may be suspended, modified or discontinued by the board of directors at any time, in its sole discretion and without notice. As of February 14, 2019, the Partnership has repurchased a total of 2,783,253 common units for a total cost of $29,426, with $70,574 remaining under its approved unit buyback program.

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Capital Requirements

During the year ended December 31, 2018, capital expenditures totaled $141,546, primarily associated with the development of our Kermit 2 facility, expansion of our Wyeville facility, equipment builds to further expand market penetration of the FB Industries silo solution, equipment purchases for PropStream and various projects at our production facilities and terminals.

Capital expenditures for the full year 2019 will be comprised of three components. Carryover growth capex from 2018 projects associated with completion of the Kermit 2 construction and Wyeville expansions are expected to be in the range of $30,000 to $35,000 to be spent primarily in the first quarter of 2019. For the full year 2019, maintenance capex is expected to be in the range of $25,000 to $30,000. Discretionary growth capex related to spending on logistics assets and continued investment in container and silo equipment for PropStream for the full year 2019, up to an additional $55,000, may be spent as market conditions dictate and as warranted by customer commitments.

Working Capital

Working capital is the amount by which current assets, excluding cash, exceed current liabilities and is a measure of our ability to pay our liabilities as they become due. At the end of any given period, accounts receivable and payable tied to sales and purchases are relatively balanced to the volume of tons sold during the period. The factors that typically cause variability in the Partnership's working capital are (1) changes in receivables due to fluctuations in volumes sold, pricing and timing of collection, (2) inventory levels, which the Partnership closely manages, or (3) major structural changes in the Partnership's asset base or business operations, such as any acquisition, divestitures or organic capital expenditures. As of December 31, 2018, we had a working capital balance of $19,041, as compared to a balance of $102,589 at December 31, 2017.

The following table summarizes our working capital as of the dates indicated. 

	Year Ended December 31,
	2018		2017
Current assets:
Accounts receivable, net	$	101,029	$	139,486
Inventories	57,089		44,272
Prepaid expenses and other current assets	13,239		4,969
Total current assets	171,357		188,727
Current liabilities:
Accounts payable	71,039		48,289
Accrued and other current liabilities	61,337		33,450
Current portion of deferred revenues	19,940		4,399
Total current liabilities	152,316		86,138
Working capital	$	19,041	$	102,589

Accounts receivable decreased by $38,457 during the year ended December 31, 2018, primarily due to a 34% year-over-year decrease in sales volumes for the fourth quarter of 2018 coupled with a higher percentage of those volumes sold FOB mine, partially offset by an increase of $3,788 for the FB Industries acquisition.

Our inventory consists primarily of sand that has been excavated and processed through the wet plant and finished goods. The increase in our inventory of $12,817 was primarily driven by the acquisition of FB Industries and a buildup of washed sand stockpiles at our Wisconsin production facilities.

Prepaid and other current assets increased $8,270 during the year ended December 31, 2018, primarily due to $5,693 from the acquisition of FB Industries, including working capital adjustments.

Accounts payable and accrued liabilities increased by $50,637 on a combined basis, including $15,616 related to the FB Industries acquisition, construction costs related to our Kermit 2 facility and the expansion of our Wyeville facility, as well as an increased percentage of volumes sold via our PropStream logistics service in the fourth quarter of 2018 as compared to the fourth quarter of 2017, resulting in higher liabilities related to logistics costs at the end of 2018.

Current portion of deferred revenues represent prepayments from customers for future deliveries of frac sand to be made within the next twelve months. The increase in deferred revenues was due to the receipt of prepayments from customers made during the year ended December 31, 2018.

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The following table provides a summary of our cash flows for the periods indicated.

	Year Ended December 31,
	2018			2017			2016
Net cash provided by (used in):
Operating activities	$	237,303		$	83,975		$	(31,932	)
Investing activities	(188,137		)	(325,120		)	(52,153		)
Financing activities	57,367			244,026			69,168

Cash Flows - Year Ended December 31, 2018 Compared to Year Ended December 31, 2017

Operating Activities

Net cash provided by operating activities was $237,303 and $83,975 for the years ended December 31, 2018 and 2017, respectively. Operating cash flows include net income of $137,595 and $76,162 during the years ended December 31, 2018 and 2017, respectively, adjusted for non-cash operating expenses and changes in working capital described above. The increase in cash flows from operations was primarily attributable to increased sales and gross profit margins combined with decreased working capital in 2018 as compared to 2017.

Investing Activities

Net cash used in investing activities was $188,137 for the year ended December 31, 2018, and consisted of $34,960 of net cash paid for the FB Industries acquisition, $14,695 of equity method investments and $141,546 of capital expenditures primarily associated with the development of our Kermit 2 facility, expansion of our Wyeville facility, equipment builds to further expand market penetration of the FB Industries silo solution, equipment purchases for PropStream and various projects at our production facilities and terminals, offset by $3,064 proceeds from the sale of property, plant and equipment.

Net cash used in investing activities was $325,120 for the year ended December 31, 2017, and consisted of the $200,830 cost of the Permian Basin Sand asset acquisition, $7,168 of equity method investments and $122,246 of capital expenditures primarily related to the construction of our Kermit facility and our new terminal facility in Pecos, Texas, offset by $5,116 of restricted cash.

Financing Activities

Net cash provided by financing activities was $57,367 for the year ended December 31, 2018, and was comprised primarily of $450,000 issuance of 9.50% Senior Notes due 2026, offset by $9,426 of repurchases of common units under the unit buyback program, $438 return of contributions to participants in our unit purchase program, $127,645 distributions paid to our unitholders, $39,516 distributions paid to members of our sponsor, $410 of payments on accrued distribution equivalent rights, $12,067 of loan origination costs and $203,378 of repayments on long-term debt, including the balance of our Term Loan Credit Facility.

Net cash provided by financing activities was $244,026 for the year ended December 31, 2017, and was comprised of $412,577 net proceeds from the issuance of 23,575,000 common units, $198,000 of cash proceeds from the term loan issuance and $438 of contributions from participants in our unit purchase program, offset by $20,000 of repurchases of common units under the unit buyback program, $13,656 of distributions paid to our unitholders, $69,215 distributions paid to members of our sponsor, $39 of payments on accrued distribution equivalent rights, $4,731 of loan origination costs, a $193,000 repayment of the Prior Term Loan Credit Facility, $44,000 repayment of our sponsor's long-term debt, payment of $17,640 in subordinated promissory notes, including PIK interest and $5,151 of repayments on other long-term debt.

Cash Flows - Year Ended December 31, 2017 Compared to Year Ended December 31, 2016

Operating Activities

Net cash provided by operating activities was $83,975 for the year ended December 31, 2017, compared to net cash used in operating activities of $31,932 for the year ended December 31, 2016. Operating cash flows include net income of $76,162 and net loss of $93,025 during the years ended December 31, 2017 and 2016, respectively, adjusted for non-cash operating expenses and changes in operating assets and liabilities described above. The increase in cash flows from operations was primarily attributable to increased sales and gross profit margins in 2017 as compared to 2016.

Investing Activities

Net cash used in investing activities was $325,120 for the year ended December 31, 2017, and consisted of the $200,830 cost of the Permian Basin Sand asset acquisition, $7,168 of equity method investments and $122,246 of capital expenditures primarily related to the construction of our Kermit facility and our new terminal facility in Pecos, Texas, offset by $5,116 of restricted cash.

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Net cash used in investing activities was $52,153 for the year ended December 31, 2016, and consisted of $10,232 of equity method investments and $45,714 of capital expenditures related to the completion of the Blair facility, completion of distribution terminal facilities in Colorado and Texas, and expansion of rail capacity at our Wyeville facility, offset by $1,403 of proceeds from the sale of property, plant and equipment and $2,390 of restricted cash.

Financing Activities

Net cash provided by financing activities was $244,026 for the year ended December 31, 2017, and was comprised of $412,577 net proceeds from the issuance of 23,575,000 common units, $198,000 of cash proceeds from the term loan issuance and $438 of contributions from participants in our unit purchase program, offset by $20,000 of repurchases of common units under the unit buyback program, $13,656 of distributions paid to our unitholders, $69,215 distributions paid to members of our sponsor, $39 of payments on accrued distribution equivalent rights, $4,731 of loan origination costs, a $193,000 repayment of the Prior Term Loan Credit Facility, $44,000 repayment of our sponsor's long-term debt, payment of $17,640 in subordinated promissory notes, including PIK interest and $5,151 of repayments on other long-term debt.

Net cash provided by financing activities was $69,168 for the year ended December 31, 2016, and was comprised of $189,037 net proceeds from the issuance of 19,550,000 common units, $17,000 proceeds from the issuance of subordinated promissory notes and borrowings under our sponsor's revolver and $111 of proceeds from participants in our unit purchase program, offset by $138 of loan origination costs, a $52,500 repayment of the outstanding balance on our Prior Revolving Credit Agreement, $78,005 of repayments on our sponsor's long-term debt and $5,896 of repayments on other long-term debt.

Contractual Obligations

The following table presents our contractual obligations and other commitments as of December 31, 2018:

	Total		Less than 1 year		1-3 years		3-5 years		More than 5 years
Repayment of Senior Notes	$	450,000	$	—	$	—	$	—	$	450,000
Interest payments on Senior Notes (a)	342,000		42,750		85,500		85,500		128,250
Repayment of other notes payable	4,852		2,194		2,658		—		—
Asset retirement obligations (b)	10,677		—		—		—		10,677
Minimum royalty payments	11,375		1,200		2,400		1,600		6,175
Operating lease obligations	163,809		36,019		65,554		31,170		31,066
Minimum purchase commitments (c)	18,718		7,346		6,169		4,526		677
Total contractual obligations	$	1,001,431	$	89,509	$	162,281	$	122,796	$	626,845

(a) Estimated interest payments on our Senior Notes is calculated using the interest rate of 9.50%.

(b) The asset retirement obligations represent the fair value of the post closure reclamation and site restoration commitments for our property and processing facilities located in Wisconsin and Texas.

(c) We have entered into service agreements with transload service providers which requires us to purchase minimum amounts of services over specific periods of time at specific locations. Our failure to purchase the minimum level of services would require us to pay shortfall fees. However, the minimum quantities set forth in the agreements are not in excess of our current forecasted requirements at these locations.

Environmental Matters

We are subject to various federal, state and local laws and regulations governing, among other things, hazardous materials, air and water emissions, environmental contamination and reclamation and the protection of the environment and natural resources. We have made, and expect to make in the future, expenditures to comply with such laws and regulations, but cannot predict the full amount of such future expenditures.

Recent Accounting Pronouncements

Refer to Note 3 - Significant Accounting Policies of the Notes to Consolidated Financial Statements in Item 15. "Exhibits, Financial Statement Schedules" of this Annual Report on Form 10-K for a description of recent accounting pronouncements.

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Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations is based on our consolidated financial statements, which have been prepared in accordance with accounting principles generally acceptable in the United States of America. The preparation of these financial statements requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the dates of the financial statements and the reported revenues and expenses during the reporting periods. We evaluate these estimates and assumptions on an ongoing basis and base our estimates on historical experience, current conditions and various other assumptions that we believe to be reasonable under the circumstances. The results of these estimates form the basis for making judgments about the carrying values of assets and liabilities as well as identifying and assessing the accounting treatment with respect to commitments and contingencies. Our actual results may materially differ from these estimates.

Listed below are the accounting policies we believe are critical to our financial statements due to the degree of uncertainty regarding the estimates or assumptions involved, and that we believe are critical to the understanding of our operations. For additional information on all our significant accounting policies, refer to Note 3 - Significant Accounting Policies of the Notes to Consolidated Financial Statements in Item 15. "Exhibits, Financial Statement Schedules" of this Annual Report on Form 10-K.

Impairment of Long-lived Assets

Recoverability of investments in property, plant and equipment, and mineral rights is evaluated annually, or more often if events or circumstances indicate the impairment of an asset may exist. Estimated future undiscounted net cash flows are calculated using estimates of proven and probable sand reserves, estimated future sales prices (considering historical and current prices, price trends and related factors) and operating costs and anticipated capital expenditures. Reductions in the carrying value of our investment are only recorded if the undiscounted cash flows are less than our book basis in the applicable assets.

Impairment losses are recognized based on the extent that the remaining investment exceeds the fair value, which is determined based upon the estimated future discounted net cash flows to be generated by the property, plant and equipment and mineral rights.

Management’s estimates of prices, recoverable proven and probable reserves and operating and capital costs are subject to certain risks and uncertainties which may affect the recoverability of our investments in property, plant and equipment. Although management has made its best estimate of these factors based on current conditions, it is reasonably possible that changes could occur in the near term, which could adversely affect management’s estimate of the net cash flows expected to be generated from its operating property.

Contingent Consideration

Accounting standards require that contingent consideration be recorded at fair value at the date of acquisition and revalued during subsequent reporting dates under the acquisition method of accounting. The estimated fair value of contingent consideration is recorded as other liabilities on the Consolidated Balance Sheet. The estimate of fair value of a contingent consideration obligation requires subjective assumptions to be made regarding future business results, discount rates and probabilities assigned to various potential business result scenarios. Any adjustments to fair value are recognized in earnings in the period identified.

Contingent consideration arrangements entered into in connection with acquisitions between entities under common control are valued at fair value at the date of acquisition and any differences between the original estimated fair value, and the actual resulting payments in the future are reflected as an equity adjustment to the deemed distributions associated with the acquisitions.

Asset Retirement Obligations

In accordance with Accounting Standards Codification ("ASC") 410-20, Asset Retirement Obligations, we recognize reclamation obligations when incurred and record them as liabilities at fair value. In addition, a corresponding increase in the carrying amount of the related asset is recorded and depreciated over such asset’s useful life. The reclamation liability is accreted to expense over the estimated productive life of the related asset and is subject to adjustments to reflect changes in value resulting from the passage of time and revisions to the estimates of either the timing or amount of the reclamation costs.

Revenue Recognition

As of January 1, 2018, we adopted the new Accounting Standards Update ("ASU") 2014-09, Revenue from Contracts with Customers (Topic 606), and all the related amendments to all contracts using the full retrospective method. The adoption of Topic 606 had no impact on our revenue recognition practices or impact to our Consolidated Financial Statements but required additional disclosures.

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We generate frac sand revenues from the sale of raw frac sand that our customers purchase for use in the oil and natural gas industry. A substantial portion of our frac sand is sold to customers with whom we have long-term supply agreements, the current terms of which expire between 2020 and 2024. The agreements define, among other commitments, the volume of product that the Partnership must provide and the volume that the customer must purchase by the end of the defined periods. Pricing structures under our agreements are in many cases subject to certain contractual adjustments and consist of a combination of negotiated pricing and fixed pricing. These arrangements may undergo negotiations regarding pricing and volume requirements, which may occur in volatile market conditions. We also sell sand through individual purchase orders executed on the spot market, at prices and other terms determined by the existing market conditions as well as the specific requirements of the customer. We typically invoice our frac sand customers as the product is delivered and title transfers to the customer, with standard collection terms of net 30 days.

Frac sand sales revenues are recognized at the point in time following the transfer of control to the customer when legal title passes, which may occur at the production facility, rail origin, terminal or wellsite. Revenue recognition is driven by the execution and delivery of frac sand by the Partnership to the customer, which is initiated by the customer placing an order for frac sand, the Partnership accepting and processing the order, and the physical delivery of sand at the location specified by the customer. At that point in time, delivery has occurred, evidence of a contractual arrangement exists and collectability is reasonably assured.

Revenue from make-whole provisions in our customer contracts is recognized as other revenue at the end of the defined period when collectability is certain. Customer prepayments in excess of customer obligations remaining on account upon the expiration or termination of a contract are recognized as other operating income during the period in which the expiration or termination occurs.

We generate other revenues primarily through the performance of our PropStream logistics service, which includes transportation, equipment rental, and labor services, as well as through activities performed at our in-basin terminals, including transloading sand for counterparties, and lease of storage space. Transportation services typically consist of transporting proppant from storage facilities to the wellsite and are contracted through work orders executed under established pricing agreements. The amount invoiced reflects the transportation services rendered. Equipment rental services provide customers with use of our PropStream fleet equipment for either contractual periods defined through formal agreements or for work orders under established pricing agreements. The amounts invoiced reflect either the contractual monthly minimum, or the length of time the equipment was utilized in the billing period. Labor services provide customers with supervisory, logistics, or field personnel through formal agreements or work orders executed under established pricing agreements. The amounts invoiced reflect either the contractual monthly minimum, or the amount of time our labor services were utilized in the billing period.

We typically invoice our customers as product is delivered and services are rendered, with standard collection terms of net 30 days. We recognize revenue for PropStream logistics services and other revenues as title of the product transfers and the services have been rendered and completed. At that point in time, delivery of service has occurred, evidence of a contractual arrangement exists and collectability is reasonably assured.

Related Party Transactions

Refer to Note 16 - Related Party Transactions of the Notes to Consolidated Financial Statements in Item 15. "Exhibits, Financial Statement Schedules" of this Annual Report on Form 10-K for additional information regarding related party transactions.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

Quantitative and Qualitative Disclosure of Market Risks

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risk. Market risk is the risk of loss arising from adverse changes in market rates and prices. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. Historically, our risks have been predominantly related to potential changes in the fair value of our long-term debt due to fluctuations in applicable market interest rates and those risks that arise in the normal course of business, as we do not engage in speculative, non-operating transactions, nor do we utilize financial instruments or derivative instruments for trading purposes.

Commodity Price Risk

The market for frac sand is indirectly exposed to fluctuations in the prices of crude oil and natural gas to the extent such fluctuations impact well completion activity levels and thus impact the activity levels of our customers in the pressure pumping industry. We do not intend to hedge our indirect exposure to commodity risk.

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Interest Rate Risk

Borrowings under the ABL Credit Facility bear interest at a rate equal to, at the Partnership’s option, either (1) a base rate plus an applicable margin ranging between 0.75% per annum and 1.50% per annum, based upon the Partnership’s leverage ratio, or (2) a LIBOR rate plus an applicable margin ranging between 1.75% per annum and 2.50% per annum, based upon the Partnership’s leverage ratio. As of December 31, 2018, we had no borrowings outstanding under the ABL Credit Facility. To the extent there are any outstanding borrowings under the ABL Credit Facility, changes in applicable interest rates would not affect the ABL Credit Facility’s fair market value, but would impact our future results of operations and cash flows. Changes in interest rates do not impact the amount of interest we pay on our Senior Notes, but can impact their fair market values. As of December 31, 2018, our Senior Notes had a carrying value of $450,000. Refer to Note 3 - Significant Accounting Policies of the Notes to Consolidated Financial Statements included in Item 15. "Exhibits, Financial Statement Schedules" of this Annual Report on Form 10-K for additional discussion on the fair value of our Senior Notes.

Foreign Currency Translation Risk

Our consolidated financial statements are expressed in U.S. dollars, but a portion of our operations is conducted in a currency other than U.S. dollars. The Canadian dollar is the functional currency of the Partnership's foreign subsidiary as it is the primary currency within the economic environment in which the subsidiary operates. Changes in the exchange rate can affect our revenues, earnings, and the carrying value of our assets and liabilities in our consolidated balance sheet, either positively or negatively. Adjustments resulting from the translation of the subsidiary's financial statements are reported in other comprehensive income (loss). For the year ended December 31, 2018, the Partnership recorded a comprehensive loss of $4,230.

Credit Risk – Customer Concentration

During the year ended December 31, 2018, sales to Chevron and Halliburton each accounted for greater than 10% of our total revenues. Our customers are generally oil and natural gas exploration and production companies and pressure pumping service providers. This concentration of counterparties operating in a single industry may increase our overall exposure to credit risk in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions. If a customer defaults or if any of our contracts expire in accordance with their terms, and we are unable to renew or replace these contracts, our gross profit and cash flows may be adversely affected.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The Report of Independent Registered Public Accounting Firm, our Consolidated Financial Statements, the accompanying Notes to the Consolidated Financial Statements, and the Financial Statement Schedule that are filed as part of this Annual Report on Form 10-K are listed under Item 15. "Exhibits, Financial Statement Schedules" and are set forth beginning on page F-1 immediately following the signature pages of this Annual Report on Form 10-K.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our general partner's 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 the end of the period covered by this Annual Report on Form 10-K. Based on such evaluation, our general partner's Chief Executive Officer and Chief Financial Officer have concluded that as of such date, our disclosure controls and procedures were effective.

Management’s Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act. Our internal control over financial reporting is a process designed under the supervision of our general partner's Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

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Because of its inherent limitations, internal control over financial reporting may not detect or prevent misstatements.  Also, projections of any evaluation of the effectiveness to future periods are subject to risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

As of December 31, 2018, our management assessed the effectiveness of our internal control over financial reporting based on the criteria for effective internal control over financial reporting established in Internal Control - Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission in 2013. Based on the assessment, management determined that we maintained effective internal control over financial reporting as of December 31, 2018, based on those criteria.

The effectiveness of our internal control over financial reporting as of December 31, 2018 has been audited by Deloitte & Touche, LLP, an independent registered public accounting firm, as stated in their audit report which appears herein.

Changes in Internal Controls Over Financial Reporting

During the quarter ended December 31, 2018, there have been no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the unitholders and the Board of Directors of Hi-Crush Partners LP

Opinion on Internal Control over Financial Reporting

We have audited the internal control over financial reporting of Hi-Crush Partners LP and subsidiaries (the “Partnership”) as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2018, of the Partnership and our report dated February 19, 2019, expressed an unqualified opinion on those financial statements.

Basis for Opinion

The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

February 19, 2019

ITEM 9B. OTHER INFORMATION

None.

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PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Management of Hi-Crush Partners LP

We are managed and operated by the board of directors and executive officers of our general partner. Under the partnership agreement, our limited partners have the right to appoint all members of the board of directors of our general partner, including the independent directors. Our general partner owes certain duties to our unitholders as well as a fiduciary duty to its owners.

Our general partner has four directors, three of whom are independent as defined under the independence standards established by the NYSE and the Exchange Act. The NYSE does not require a listed publicly-traded partnership, such as ours, to have a majority of independent directors on the board of directors of our general partner or to establish a compensation committee or a nominating committee. However, our general partner is required to have an audit committee of at least three members, and all its members are required to meet the independence and experience standards established by the NYSE and the Exchange Act. As of December 31, 2018, the following directors served on the audit committee:

Name	Independence Status
John F. Affleck-Graves	Independent
John Kevin Poorman	Independent
Joseph C. Winkler III	Independent

Following the IPO on August 16, 2012, neither our general partner nor our previous sponsor received any management fee or other compensation in connection with our general partner’s management of our business, but we reimbursed our general partner and its affiliates, and during the period from our IPO to the closing of the Sponsor Contribution, we reimbursed our previous sponsor for all expenses they incurred and payments they made on our behalf. Our partnership agreement did not set a limit on the amount of expenses for which our general partner and its affiliates could be reimbursed. These expenses included salary, bonus, incentive compensation and other amounts paid to persons who performed services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our partnership agreement provided that our general partner determined in good faith the expenses that are allocable to us.

In evaluating director candidates, we assess whether a candidate possesses the integrity, judgment, knowledge, experience, skill and expertise that are likely to enhance the board’s ability to manage and direct our affairs and business, including, when applicable, to enhance the ability of committees of the board to fulfill their duties.

Executive Officers and Directors of Our General Partner

The following table shows information for the executive officers and directors of our general partner. Directors are classified with respect to their terms of office by dividing them into three classes, designated Class I, Class II and Class III, each class to be as nearly equal in number as possible. The Board currently consists of four directors, of which two are in Class I, one is in Class II and one is in Class III.  Messrs. Affleck-Graves and Poorman have each been designated a Class I director and will serve an initial term of office that expires at the 2020 annual meeting, Mr. Winkler has been designated a Class II director and will serve for an initial term that expires at the 2021 annual meeting and Mr. Rasmus has been designated a Class III director and will serve for an initial term that expires at the 2022 annual meeting.  Commencing with the election of directors at the 2020 annual meeting, each director will hold office for the term ending on the date of the third annual meeting following the annual meeting at which such director’s class was elected, or until such director’s earlier death, resignation or removal. Executive officers serve at the discretion of the board. There are no family relationships among any of our directors or executive officers.

Name	Age	Position With Our General Partner
Robert E. Rasmus	61	Chief Executive Officer and Chairman of the Board
Laura C. Fulton	55	Chief Financial Officer
Mark C. Skolos	59	General Counsel, Chief Compliance Officer and Secretary
William E. Barker	37	Principal Strategy Officer
John F. Affleck-Graves	68	Director
John Kevin Poorman	67	Director
Joseph C. Winkler III	67	Director

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Robert E. Rasmus—Chief Executive Officer and Chairman of the Board. Mr. Rasmus is a co-founder of Hi-Crush Proppants LLC and served as its Co-Chief Executive Officer since its formation in October 2010 until November 2015 when he became sole Chief Executive Officer. Mr. Rasmus was named Co-Chief Executive Officer and appointed to the board of directors of our general partner in May 2012 until November 2015 when he became sole Chief Executive Officer. Mr. Rasmus was a founding member of Red Oak Capital Management LLC ("ROCM") in June 2002 and has served as Managing Director since inception. ROCM’s business model centered on partnering with the largest oil services companies in unconventional basins in the United States. Prior to the founding of ROCM, Mr. Rasmus was the President of Thunderbolt Capital Corp., a venture firm focused on start-up and early stage private equity investments. Previously, Mr. Rasmus started, built and expanded a variety of domestic and international capital markets and corporate finance businesses. Mr. Rasmus was the Senior Managing Director of Banc One Capital Markets, Inc. (formerly First Chicago Capital Markets, Inc.) where he was responsible for the high yield and private placement businesses while functioning as a member of the management committee. Prior thereto, Mr. Rasmus was the Managing Director and Head of Investment Banking in London for First Chicago Ltd. Mr. Rasmus holds a BA in Government and International Relations from the University of Notre Dame. Mr. Rasmus is a member of the board of directors for the Lab for Economic Opportunities. We believe that Mr. Rasmus’ industry experience and deep knowledge of our business makes him well-suited to serve on the board of directors of our general partner.

Laura C. Fulton—Chief Financial Officer. Ms. Fulton has served as Chief Financial Officer of Hi-Crush Proppants LLC since April 2012. In May 2012, Ms. Fulton was appointed to Chief Financial Officer of our general partner. On February 26, 2013, Ms. Fulton was elected director of Targa Resources Corp. and currently serves on its audit committee. From March 2008 to October 2011, Ms. Fulton served as the Executive Vice President, Accounting and then Executive Vice President, Chief Financial Officer of AEI Services, LLC ("AEI"), an owner and operator of essential energy infrastructure assets in emerging markets. Prior to AEI, Ms. Fulton spent 12 years with Lyondell Chemical Company in various capacities, including as general auditor responsible for internal audit and the Sarbanes-Oxley certification process, and as the assistant controller. Previously, Ms. Fulton worked for Deloitte & Touche in its audit and assurance practice for 11 years. Ms. Fulton is a CPA and graduated cum laude from Texas A&M University with a BBA in Accounting. Ms. Fulton is a member of the American Institute of Certified Public Accountants and serves on the Mays Business School Dean's Advisory Board and the Accounting Department Advisory Board at Texas A&M University.

Mark C. Skolos—General Counsel, Chief Compliance Officer and Secretary. Mr. Skolos was appointed General Counsel of Hi-Crush Proppants LLC in April 2012 and named General Counsel and Secretary of our general partner in May 2012. Mr. Skolos was named Chief Compliance Officer of our general partner in September 2018. Prior to joining Hi-Crush Proppants LLC, Mr. Skolos was a shareholder at the law firm of Weld, Riley, Prenn and Ricci S.C. ("Weld Riley") from September 2011 to April 2012. Mr. Skolos worked as an attorney for Skolos, Millis and Matousek, S.C., or its predecessor firms ("Skolos Millis"), for 26 years prior to its merger with Weld Riley in April 2012. Mr. Skolos was made a shareholder at Skolos Millis in 1990. In his private practice, Mr. Skolos represented developers, businesses and local units of government on issues of government regulation, land use and real estate. Mr. Skolos has extensive experience representing companies in the non-metallic mining and processing industry on a wide spectrum of issues, including permitting, land acquisition and government relations. He graduated from the University of Wisconsin Law School in 1985 with a JD. Mr. Skolos has served as President of the Tri-County Bar Association of Wisconsin and acted as both Circuit Court and Family Court Commissioner in the State of Wisconsin. He is on the board of directors for the National Industrial Sand Association and is a member of the Texas General Counsel Forum.

William E. Barker—Principal Strategy Officer. In August 2017, Mr. Barker assumed the role of Principal Strategy Officer. Prior to that, Mr. Barker was responsible for logistics, site development, terminal operations and inventory management as Vice President of Midstream Operations. From September 2013 to February 2015, he served as Assistant General Counsel of Hi-Crush Proppants LLC.  Prior to joining Hi-Crush Proppants LLC, from September 2008 to September 2013, Mr. Barker specialized in securities law and mergers and acquisitions for the law firm of Norton Rose Fulbright US LLP.  Mr. Barker holds a Bachelor of Arts degree in Economics from Rice University, where he graduated magna cum laude, and a Juris Doctorate from the University of Houston Law Center, where he graduated as a member of the Order of the Coif.

John F. Affleck-Graves—Director. Mr. Affleck-Graves joined the board of directors of our general partner in November 2012 and serves as a member of the audit committee and conflicts committee. He has served in roles of increasing responsibility and seniority at The University of Notre Dame from 1986 to present, including as an Executive Vice President from 2004 to present. As Executive Vice President, he serves as one of three executive officers of the University. Additionally, Mr. Affleck-Graves is a prior Board member of St. Joseph’s Capital Bank, Student Loan Corporation and Express-1 Inc. Throughout his career, Mr. Affleck-Graves has received many distinctions and honors including MBA Outstanding Teacher Award, University of Notre Dame. He received his BSc Mathematical Statistics and Computer Science in 1971 from the University of Capetown. Mr. Affleck-Graves also holds a PhD in Mathematical Statistics and a BCom in Accounting and Financial Management from the University of Capetown. Mr. Affleck-Graves previously served as a director of Express-1 Expedited Solutions, Inc. from October 2006 to October 2011 and served on its audit committee. We believe that Mr. Affleck-Graves’ expertise and the unique perspective gained from his service at the University of Notre Dame enable him to effectively serve as a director.

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John Kevin Poorman—Director. Mr. Poorman joined the board of directors of our general partner in August 2013 and serves as a member of the audit committee and conflicts committee. Since June 2013, Mr. Poorman has been Chief Executive Officer of PSP Capital Partners, LLC and Pritzker Realty Group, LLC, investment managers for affiliated entities in real estate and other non-real estate business. Pritzker Realty Group, LLC is also an operator of real estate. Mr. Poorman is responsible for implementing and overseeing each company's strategic direction. He is also Executive Chairman of Vi Senior Living (formerly Classic Residence by Hyatt). Mr. Poorman previously served as an officer and director of several businesses owned by interests of the extended Pritzker family. Mr. Poorman is the past Chairman of the Board of Trustees of the Loyola University of New Orleans and served as a director of The New Orleans Jazz Orchestra, Inc. Mr. Poorman also serves as President and as a director of The Barack Obama Foundation. Prior to joining Hyatt Hotels Corporation in 1988, Mr. Poorman was a partner in the Dallas-based law firm of Johnson & Swanson. Mr. Poorman graduated from the University of Oklahoma in 1974 with a B.S. in Botany and received a Juris Doctorate therefrom in 1977 with highest honors. He is a member of the State Bars of the States of Texas and Illinois. We believe that Mr. Poorman’s business leadership skills make him well-suited to serve on the board of directors of our general partner.

Joseph C. Winkler III—Director. Mr. Winkler joined the board of directors of our general partner in August 2012 and serves as the Chairman of the audit committee and conflicts committee. Mr. Winkler served as Chairman and Chief Executive Officer of NYSE-listed Complete Production Services, Inc. ("Complete"), a provider of specialized oil and gas services and equipment in North America, from March 2007 until February 2012, at which time Complete was acquired by Superior Energy Services, Inc. From June 2005 to March 2007, Mr. Winkler served as Complete’s President and Chief Executive Officer. From March 2005 until June 2005, Mr. Winkler served as the Executive Vice President and Chief Operating Officer of National Oilwell Varco, Inc., an oilfield capital equipment and services company, and from May 2003 until March 2005 as the President and Chief Operating Officer of the company’s predecessor, Varco International, Inc. ("Varco"). From April 1996 until May 2003, Mr. Winkler served in various other capacities with Varco and its predecessor, including Executive Vice President and Chief Financial Officer. From 1993 to April 1996, Mr. Winkler served as the Chief Financial Officer of D.O.S., Ltd., a privately held provider of solids control equipment and services and coil tubing equipment to the oil and gas industry, which was acquired by Varco in April 1996. Prior to joining D.O.S., Ltd., Mr. Winkler served as Chief Financial Officer of Baker Hughes INTEQ, and served in a similar role for various companies owned by Baker Hughes Incorporated including Eastman/Telco and Milpark Drilling Fluids. Mr. Winkler served as a member of the board of directors of Dresser-Rand Group, Inc., a NYSE-listed provider of rating equipment solutions, until its acquisition by Siemens in July 2015. Mr. Winkler serves as lead director of the board of directors of Commercial Metals Company, a vertically integrated Fortune 500 steel company, and serves on its Finance Committee and Compensation Committee, and a member of the board of directors of Eclipse Resources Corporation, an independent exploration and production company, and serves on its audit and compensation committees. Mr. Winkler joined the board of directors of Tetra Technologies Inc. in August 2015 and is a member of its audit and compensation committees. Mr. Winkler received a BS degree in Accounting from Louisiana State University. We believe that Mr. Winkler’s many years of operational, financial, international and capital markets experience, a significant portion of which was with publicly traded companies in the oil and gas services, manufacturing and exploration and production industries, make him particularly well-suited to serve on the board of directors of our general partner.

Director Independence

As of December 31, 2018, our three directors that serve on our audit committee were independent.

Committees of the Board of Directors

The board of directors of our general partner maintains an audit committee and a conflicts committee. As permitted by NYSE rules, we do not currently have a compensation committee, but rather the board of directors of our general partner approves equity grants to directors and employees.

Audit Committee

We are required to have an audit committee of at least three members, and all its members are required to meet the independence and experience standards established by the NYSE and the Exchange Act. The audit committee assists the board of directors of our general partner in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and partnership policies and controls. The audit committee has the sole authority to (1) retain and terminate our independent registered public accounting firm, (2) approve all auditing services and related fees and the terms thereof performed by our independent registered public accounting firm, and (3) pre-approve any non-audit services and tax services to be rendered by our independent registered public accounting firm. The audit committee is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm is given unrestricted access to the audit committee and our management, as necessary. Messrs. Winkler, Affleck-Graves and Poorman are the members of the audit committee, with Mr. Winkler currently serving as chairman.

The board of directors of our general partner has determined that Mr. Winkler qualifies as an "audit committee financial expert," as such term is defined under SEC rules.

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The audit committee has (1) reviewed and discussed the audited financial statements with management, (2) discussed with the independent auditors the matters required by PCAOB Auditing Standard No. 16, Communications with Audit Committees, (3) received written disclosures and the letter from the independent accountants required by applicable requirements of the PCAOB regarding the independent accountant's communications with the audit committee concerning independence and has discussed with the independent accountant the independent accountant's independence, and (4) recommended to the board of directors of our general partner that the audited financial statements be included in the Partnership's Annual Report on Form 10-K for the last fiscal year.

Conflicts Committee

Three independent members of the board of directors of our general partner serve on the conflicts committee to review specific matters that the board believes may involve conflicts of interest and determines to submit to the conflicts committee for review. The conflicts committee determines if the resolution of the conflict of interest is in our best interest. The members of the conflicts committee may not be officers or employees of our general partner or directors, officers or employees of its affiliates and must meet the independence standards established by the NYSE and the Exchange Act to serve on an audit committee of a board of directors, along with other requirements in our partnership agreement. Any matters approved by the conflicts committee are conclusively deemed to be in our best interest, approved by all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders. Messrs. Winkler, Affleck-Graves and Poorman are the members of the conflicts committee, with Mr. Winkler currently serving as chairman.

Section 16(a) Beneficial Ownership Reporting Compliance

Pursuant to Section 16(a) of the Exchange Act, certain officers and directors of our general partner, and persons beneficially owning more than 10% of our units, are required to file with the SEC reports of their initial ownership and changes in ownership of our units. These officers and directors, and persons beneficially owning more than 10% of our units are also required by SEC regulations to furnish us with copies of all Section 16(a) forms they file. Based solely on a review of Forms 3, 4 and 5 and amendments thereto furnished to us and written representations from reporting persons that no other reports were required for those persons, we believe that during 2018, all officers and directors, and persons beneficially owning more than 10% of our units who were required to file reports under Section 16(a) complied with such requirements on a timely basis.

Corporate Governance Matters

We have a Code of Business Conduct and Ethics for directors, executive officers and employees that applies to, among others, the principal executive officers, principal financial officer and principal accounting officer or controller of our general partner, as required by SEC and NYSE rules. Furthermore, we have Corporate Governance Guidelines and charters for our Audit Committee and Conflicts Committee. Each of the foregoing is available on our website at www.hicrush.com in the "Corporate Governance" section. We provide copies, free of charge, of any of the foregoing upon receipt of a written request to Hi-Crush Partners LP, 1330 Post Oak Blvd, Suite 600, Houston, Texas 77056, Attn: General Counsel. We disclose amendments and director and executive officer waivers with regard to the Code of Business Conduct and Ethics, if any, on our website or by filing a Current Report on Form 8-K to the extent required.

The certifications of our general partner’s Chief Executive Officer and Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act have been included as exhibits to this Annual Report on Form 10-K.

Communication with the Board of Directors

A holder of our units or other interested party who wishes to communicate with the directors of our general partner may do so by contacting our corporate secretary at the address or phone number appearing on the front page of this Annual Report on Form 10-K. Communications will be relayed to the intended recipient of the board of directors of our general partner except in instances where it is deemed unnecessary or inappropriate to do so pursuant to our communications policy, which is available on our website at www.hicrush.com in the "Corporate Governance" section. Any communications withheld under those guidelines will nonetheless be recorded and available for any director who wishes to review them.

Executive Sessions of Non-Management Directors

The board of directors of our general partner holds regular executive sessions in which the independent directors meet without any non-independent directors or members of management. The purpose of these executive sessions is to promote open and candid discussion among the independent directors. The director who presides at these meetings, the Lead Director, is chosen by the board of directors of our general partner to serve until the first meeting of the Board to occur after the first anniversary of the date that the Lead Director is chosen. The current Lead Director is Mr. Winkler.

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ITEM 11. EXECUTIVE COMPENSATION

(All amounts presented in dollars)

Compensation Discussion and Analysis

General

As a publicly traded limited partnership, we do not have directors, officers or employees. Instead, we are managed by the board of directors of our general partner, Hi-Crush GP LLC, and the executive officers of our general partner perform all of our management functions.

For the year ended December 31, 2018, the named executive officers of our general partner were the following:

• Robert E. Rasmus, Chief Executive Officer (Principal Executive Officer)

• Laura C. Fulton, Chief Financial Officer (Principal Financial Officer)

• Mark C. Skolos, General Counsel, Chief Compliance Officer and Secretary

• William E. Barker, Principal Strategy Officer

• Scott J. Preston, Chief Operating Officer (a)

(a) Mr. Preston was appointed Chief Operating Officer of our general partner effective April 2, 2018. Effective December 12, 2018, Mr. Preston was no longer employed by the company. Mr. Rasmus assumed the role as our Principal Operating Officer effective December 12, 2018 upon Mr. Preston’s resignation.

Compensation Decisions Prior to the Sponsor Contribution

Prior to the Sponsor Contribution, other than equity-based incentive grants under our long-term incentive plan, our sponsor, as the ultimate employer of our named executive officers, had responsibility and authority for non-equity-based compensation related decisions for our Chief Executive Officer and, upon consultation with and recommendations by our Chief Executive Officer, for our other executive officers. Although our sponsor had the ultimate responsibility and authority for non-equity-based compensation related decisions for our named executive officers, it regularly consulted with, received recommendations from, and obtained the approval of, the board of directors of our general partner. All determinations with respect to equity awards made under the Partnership’s First Amended and Restated Long-Term Incentive Plan (the "LTIP") were made by the board of directors of our general partner, following the recommendation of our sponsor and the approval of the board of directors of our general partner.

Compensation Decisions Following the Sponsor Contribution

Following the Sponsor Contribution, the board of directors of our general partner has responsibility and authority for all compensation related decisions for our Chief Executive Officer and, upon consultation with and recommendation by our Chief Executive Officer, for our other executive officers. All compensation decisions for all other employees of the general partner and Hi-Crush Services are made at the discretion of our Chief Executive Officer.

Distributions to Our General Partner

Prior to the Sponsor Contribution, our general partner was directly owned by our sponsor, which was partially-owned by certain of our named executive officers. We paid quarterly distributions to our sponsor in accordance with our partnership agreement with respect to its ownership of its limited partner interests and the incentive distribution rights as specified in the partnership agreement. The amount of each quarterly distribution that we paid to our sponsor was based solely on the provisions of our partnership agreement, which agreement specified the amount of cash we distributed to our sponsor based on the amount of cash that we distributed to our limited partners each quarter. Accordingly, the cash distributions we made prior to October 21, 2018 to our sponsor bore no relationship to the level or components of compensation of our named executive officers.

Summary of 2018 Compensation Actions and Changes

Peer Group Review and Selection

Each year, BDO USA LLP ("BDO"), our independent executive compensation consultant, prepares an analysis covering all major components of total compensation, including annual base salary, annual short-term cash incentive and long-term incentive awards for the named executive officers. The board of directors of our general partner utilizes the information provided by BDO to compare the levels of annual base salary, annual short-term cash incentive and long-term equity incentive awards at the peer companies with those of its named executive officers to ensure that the compensation of our named executive officers is both consistent with our compensation philosophy and competitive relative to the compensation for executive officers of the peer companies.

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For the 2018 analysis, BDO was asked to develop and recommend an updated compensation benchmarking peer group as well as to develop a performance peer group of companies against which to measure our Total Unitholder Return ("TUR") performance in lieu of the Alerian MLP index of companies, as described under "Components of Executive Compensation-Long-Term Incentive Compensation" below.

After BDO's selection and recommendation of the new executive compensation benchmarking peer group, which was approved by the board of directors of our general partner. BDO completed a benchmarking study and data regression analysis using its multiple regression model considering the Partnership's 2017 Market Cap, Total Assets and Adjusted EBITDA. BDO also analyzed survey data from published executive compensation surveys at the 25^th, 50^th and 75^th percentiles using energy sector cuts representing companies with revenues ranging from $500 million to $1 billion for certain positions where there was insufficient data to perform valid regression analysis.

Establishment of Total Direct Compensation Value for the Chief Executive Officer

Based on the results of the study, the total direct compensation target approved in 2018 for Mr. Rasmus includes a base pay component which is 21% of the total compensation mix and variable pay components which comprise 79% of the total compensation mix. The variable component includes an annual, short-term incentive component which, if earned, is paid in cash, and grants of long-term equity-settled incentive awards granted in performance based vesting phantom limited partner units ("PPUs") (50% of value) and time-based phantom limited partner units ("TPUs") (50% of value). Following is a summary of the total direct compensation target established for Mr. Rasmus in 2018:

Name	Base Salary		STI Target		Annual LTI Target		Total Direct Compensation Target
Robert E. Rasmus, Chief Executive Officer	$	600,000	$	600,000	$	1,620,000	$	2,820,000

Base Salary

No base salary increases were recommended or approved for any of the named executive officers in 2018.

Short-Term Cash and Long-Term Incentive Targets

No changes were made to the named executive officers' annual short-term cash incentive targets for 2018. Long-term incentive award targets were adjusted based on the analysis provided by BDO for each of the named executive officers.

Our Compensation Philosophy

Our executive compensation program is intended to align the interests of our management team with those of our unitholders by motivating our executive officers to achieve strong financial and operating results for us, which we believe closely correlate to long-term unitholder value. In addition, our program is designed to achieve the following objectives:

• attract, retain and reward talented executive officers and key management employees by providing total compensation competitive with that of executive officers at companies with which we compete for talent;

• motivate executive officers and key management employees to achieve strong financial and operational performance;

• emphasize performance-based compensation, balancing short-term and long-term results; and

• reward individual performance.

Methodology - Advisors and Peer Companies

We employ a compensation philosophy that emphasizes pay-for-performance based on a combination of the Partnership’s performance and the individual’s impact on the Partnership’s performance, advancement of our business strategies, levels of responsibility, skills and experience. We believe this pay-for-performance approach generally aligns the interests of our named executive officers with that of our unitholders, and at the same time enables us to maintain a lower level of base salary overhead in the event our operating and financial performance fails to meet expectations. Our executive compensation program is designed to attract and retain individuals with the background and skills necessary to successfully execute our business model in a demanding environment, to motivate those individuals to reach near-term and long-term goals in a way that aligns their interest with that of our unitholders, and to reward success in reaching such goals.

When evaluating compensation levels for each named executive officer, the sponsor (prior to the Sponsor Contribution) and the board of directors of our general partner reviews publicly available compensation data for executives in our peer group as well as compensation surveys needed to supplement data for positions where there is insufficient data or a lack of comparable positions reported within the peer group. The peer group data analysis and compensation survey data each serve as reference points along with the observations of the Chief Executive Officer as provided to the sponsor (prior to the Sponsor Contribution) and the board of directors of our general partner regarding skills, experience, roles and responsibilities, objectives, as well as other factors, to determine the appropriate salary and total compensation target level for each named executive officer.

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In developing a new benchmarking peer group, BDO consulted with members of the board of directors of our general partner as well as management. Potential peer companies were considered whose size, as measured by market capitalization, total assets, and EBITDA, may be substantially greater than that of the Partnership but for which helpful data is available through public filings. To account for company size, BDO uses statistical analysis to correct for variations in size. More specifically, BDO uses multiple regression analysis of peer data to predict what a reasonable total compensation amount might be for a unique executive position. BDO believes that larger sample sizes result in stronger correlations of data.

Upon completion of the due diligence, five of the 18 companies from our prior benchmarking peer group were removed due to M&A activity or because they no longer met the revenue parameters: DCP Midstream, LP, Western Refining Inc., Crestwood Equity Partners, Calumet Specialty Products Partners, LP, and Carbo Ceramics Inc..

To expand the peer group in alignment with changes to our business and after the careful review of 75 potential peer companies, 13 companies were selected for addition to 13 of the original peer group of companies for a total of 26 peer companies. The 13 newly selected peer companies are: Western Gas Partners, LP, SemGroup Corporation, Cimarex Energy Company, Newfield Exploration Company, FTS International, Inc., Diamondback Energy, Inc., Energen Corporation, Unit Corporation, Matador Resources Company, Centennial Resource Development, Inc., Callon Petroleum Company, Range Resources Corporation and Concho Resources Inc.

The final group of 26 peer companies was utilized by BDO to complete the benchmarking study to review and establish overall competitive compensation targets for our named executive officers. BDO used its multiple regression model to determine how market capitalization and total assets as well as EBITDA of companies in the peer group predict the value of total compensation opportunity of a company whose market capitalization and total assets equal those of Hi-Crush.

We consider BDO to be independent of the Partnership under the factors set forth in Section 303A.05 of the NYSE Listed Company Manual, and therefore the work performed by BDO does not create a conflict of interest. The BDO study was based on compensation as reported in annual reports, proxy statements and Form 8-K filings by each company in the peer group.

The study was comprised of the following 26 peer companies:

American Midstream Partners, LP	Holly Energy Partners LP
Antero Midstream Partners LP	Liberty Oilfield Services Inc.
Boardwalk Pipeline Partners, LP	Martin Midstream Partners L.P.
Callon Petroleum Company	Matador Resources Company
Centennial Resource Development, Inc.	Newfield Exploration Company
Cimarex Energy Company	NuStar Energy L.P.
Concho Resources Inc.	Range Resources Corporation
Covia Holdings Corporation	SemGroup Corporation
Diamondback Energy, Inc.	Summit Midstream Partners, LP
Dominion Midstream Partners, LP	Tallgrass Energy Partners LP
Energen Corporation	U.S. Silica Holdings, Inc.
FTS International, Inc.	Unit Corporation
Genesis Energy, L.P.	Western Gas Partners, LP

The compensation analysis provided by BDO covered all major components of total compensation, including annual base salary, annual short-term cash incentive and long-term incentive awards for the senior executives of these companies. The board of directors of our general partner utilized the information provided by BDO to compare the levels of annual base salary, annual short-term cash incentive and long-term equity incentive awards at the peer companies with those of its named executive officers to ensure that compensation of our named executive officers is both consistent with our compensation philosophy and competitive with the compensation for executive officers of the peer companies. The board of directors of our general partner also considered and reviewed the results of the study performed by BDO to ensure the results indicated that our compensation programs were yielding a competitive total compensation model prioritizing incentive-based compensation and rewarding achievement of short and long-term performance objectives.

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Components of Executive Compensation

There are principally three components of compensation that are used in our executive compensation program - base salary, annual short-term cash incentive and long-term equity incentive awards. Cash incentives and equity incentives (as opposed to base salary and benefits) represent the performance driven elements of the compensation program. The determination of each individual’s short-term cash incentives will reflect their relative contribution to achieving or exceeding annual goals, and the determination of each individual’s long-term incentive awards will be based on their expected contribution with respect to longer term performance objectives.

Base Salary

Base salary is paid in cash and is a component which recognizes each executive officer's unique value and contributions to our success in light of salary norms in the industry, provides our named executive officers with sufficient, regularly paid income and reflects position and level of responsibility. Our sponsor (prior to the Sponsor Contribution) and the board of directors of our general partner review base salaries on an annual basis and may make adjustments as necessary to maintain a competitive executive compensation structure.

In December 2018, the board of directors of our general partner determined that it was appropriate to maintain the base salaries of the named executive officers with no changes. The actual base salaries paid by us to our named executive officers during 2018 are set forth in the "Summary Compensation Table."

Named Executive Officer	2018 Annual Base Salary
Robert E. Rasmus, Chief Executive Officer	$	600,000
Laura C. Fulton, Chief Financial Officer	$	365,000
Mark C. Skolos, General Counsel, Chief Compliance Officer and Secretary	$	335,000
William E. Barker, Principal Strategy Officer	$	260,000
Scott J. Preston, Chief Operating Officer	$	365,000

Annual Short-Term Cash Incentive

Under the short-term incentive plan ("STI"), annual cash incentives are provided to executives to promote the achievement of our near term performance goals and objectives. Target incentive opportunities under the STI are established as a percentage of base salary. Incentive amounts are based on the attainment of pre-established financial goals, operational performance and individual performance objectives related to strategic activities for the function or business unit as applicable.

Our goal is to set incentive target awards at levels that make total direct compensation competitive with comparable companies for the skills, experience and requirements of similar positions in order to attract and retain top talent.  The incentive target awards can differ from actual awards because of Partnership or individual performance, but the actual payout of any award is determined at the sole discretion of the board of directors of our general partner. The incentive targets for 2018 were maintained at the 2017 levels, as set forth below:

Name and Principal Position	2018 Targeted STI Opportunity
Robert E. Rasmus, Chief Executive Officer	100% of base salary
Laura C. Fulton, Chief Financial Officer	85% of base salary
Mark C. Skolos, General Counsel, Chief Compliance Officer and Secretary	85% of base salary
William E. Barker, Principal Strategy Officer	50% of base salary
Scott J. Preston, Chief Operating Officer	85% of base salary

The following table shows each named executive officer’s performance-based cash incentive minimum, threshold, target and maximum payouts under the STI, which were established by our sponsor and the board of directors of our general partner in 2017 and reviewed in 2018 by the board of directors for named executive officers.

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Name and Principal Position	Minimum Payout ($)	Threshold Payout ($)	Target Payout ($)	Maximum Payout ($)
Robert E. Rasmus, Chief Executive Officer	—	300,000	600,000	1,200,000
Laura C. Fulton, Chief Financial Officer	—	155,125	310,250	620,500
Mark C. Skolos, General Counsel, Chief Compliance Officer and Secretary	—	142,375	284,750	569,500
William E. Barker, Principal Strategy Officer	—	65,000	130,000	260,000
Scott J. Preston, Chief Operating Officer	—	155,125	310,250	620,500

The STI provides funding for payouts based on financial, operating, and individual performance in the following range: (i) 0% if the threshold level of performance is not achieved, (ii) 50% if the threshold level of performance is achieved, (iii) 100% if the target level of performance is achieved, and (iv) 200% if the maximum level of performance is achieved. Performance levels are determined at the sole discretion of the board of directors of our general partner based on qualitative and quantitative evaluations of performance.

When determining the funding of the STI pool and the payment of individual STI awards for the year, the board of directors of our general partner considers recommendations made by the Chief Executive Officer, which are based on his evaluation of whether, and to what extent, our Partnership met its financial and operational performance objectives during the year. He also makes recommendations based on his assessment of the individual performance of each of the other named executive officers in executing their goals and objectives, which align to strategic scorecard opportunities. Any STI award paid to the Chief Executive Officer is determined by the board of directors of our general partner based upon a similar review performed as described above without input from the Chief Executive Officer. The board of directors of our general partner ultimately determines at their discretion the total amount to be allocated to the STI pool based on their final assessment of overall annual performance.

Our Partnership performance goals and objectives are based on performance indicators that align with strategies to optimize the performance of the Partnership.

The financial growth objectives for the 2018 STI were as follows:

(1) Achievement of our budget for Adjusted EBITDA (a non-GAAP measure defined as EBITDA adjusted for any non-cash impairments of goodwill and long-lived assets, earnings (loss) from equity method investments and loss on extinguishment of debt), of $333.1 million (weighted 50%);

(2) Budgeted Growth in Cash Distributions to Unitholders equal to $0.95 in 2018 (weighted 25%), and

(3) Achievement of Year-Over-Year Growth of 15% in TUR (weighted 25%).

Adjusted EBITDA is a key indicator of the short-term financial performance of our assets without regard to financing methods, capital structure or historical cost basis. Cash distributions to unitholders is an important metric used by management to compare the Partnership’s cash generating performance from period to period and to compare cash generating performance for specific periods to the cash distributions (if any) that are expected to be paid to our unitholders. Growth in total unitholder return allows us to compare annual return performance to similarly situated companies and reinforces our objective to drive near-term and long-term value creation.

The annual budget sets expectations for sales volumes, pricing, operating expenditures, capital expenditures, and general and administrative costs so that we can forecast our financial position for mid-term and long-term periods. The annual budget process includes extensive input and reviews by the sales, production, logistics, distribution operations, human resources, inventory, and financial teams generating multiple preliminary reviews by executive management and ultimately a preliminary review with the board of directors of our general partner before final approval in the December/January timeframe each year.

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In addition to financial growth objectives, funding of the STI pool is contingent upon the achievement of goals tied to applicable strategic operating and individual performance indicators, to be targeted by each named executive officer for that particular calendar year, as reviewed and approved by the board of directors of our general partner. These include:

• Meeting plant production uptime and operating efficiency goals;

• Minimizing and containing logistics costs below plan;

• Increasing logistics and production capacity and flexibility through organic expansion;

• Enhancing pricing, gaining market share and expanding our customer base;

• Diversifying our business to meet customer demands and create new opportunities;

• Streamlining processes to reduce and eliminate costs;

• Enhancing our capital structure; and

• Meeting environmental, health and safety goals.

The STI payout for Mr. Rasmus is weighted 90% on the Partnership’s financial growth objectives and 10% on the applicable strategic individual and operating objectives.

The STI payout for Ms. Fulton is weighted 75% on the Partnership’s financial growth objectives and 25% on the applicable strategic individual and operating objectives.

The STI payout for Mr. Skolos is weighted 70% on the Partnership's financial growth objectives and 30% on commercial support and environmental and regulatory compliance and other strategic individual and operating objectives.

The STI payout for Mr. Barker is weighted 75% on the Partnership's financial growth objectives and 25% on strategic individual objectives.

The STI payout for Mr. Preston is weighted 50% on the Partnership's financial growth objectives, 30% on the applicable operating objectives, and 20% on strategic individual objectives.

The board of directors of our general partner may also subjectively consider the individual leadership and performance of each officer with respect to the Partnership's achievement of these goals and objectives. Additionally, the board of directors of our general partner may apply discretion in determining actual payouts below stated maximums based on its assessment of the Partnership’s overall performance for the year.

For purposes of determining the actual funding of the STI pool, the board of directors of our general partner reviewed the 2018 Partnership results as summarized below:

Financial Growth Objectives

Adjusted EBITDA in millions
Threshold	Target	Maximum	Actual	Payout Factor
$266.5	$333.1	$399.7	$206.1	—%

Growth in Cash Distributions to Unitholders
Threshold	Target	Maximum	Actual	Payout Factor
$0.72	$0.95	$1.04	$1.40	200%

Year-Over-Year Growth in Total Unitholder Return %
Threshold	Target	Maximum	Actual	Payout Factor
10%	15%	20%	(53)%	—%

Performance relative to Adjusted EBITDA and Year-Over-Year Growth in TUR was below threshold yielding a payout factor of zero for each of these two metrics. Our 2018 TUR performance of (53)% is calculated based on the December 29, 2017 closing unit price of $10.70 and the December 31, 2018 closing unit price of $3.58 and four quarterly distributions of $0.20 (February 13, 2018), $0.225 (May 15, 2018), $0.75 (August 14, 2018), and $0.225 (November 14, 2018). Our budgeted Growth in Cash Distributions to Unitholders was $0.95 and our actual distributions totaled $1.40 based on the four quarterly distributions declared and paid in 2018, which yields a payout factor of 200%.

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Operating Objectives

In addition to our financial results, the board of directors of the general partner reviewed performance relative to our key operating objectives, where applicable, to each named executive officer:

• Production optimization goals, including uptime efficiency (operating hours per day divided by 24 hours assuming scheduled and unscheduled downtime for maintenance, checks and repairs) and operating efficiency;

• Goals to reduce supply chain operating and logistics costs;

• Safety and Environmental Compliance goals

Funding based on attainment of operating objectives under the STI may range as follows: (i) 0% if the threshold level of performance is not achieved, (ii) 50% if the threshold level of performance is achieved, (iii) 100% if the target level of performance is achieved, and (iv) 200% if the maximum level of performance is achieved. For each of the 2018 operating objectives, actual performance ranged between target and maximum levels for safety, regulatory and environmental compliance, plant uptime and operating efficiency goals and improvement in planned costs on a per ton basis for plant operations. Actual performance was at threshold or below threshold for achievement of operating costs below planned costs on a per ton basis as well as other specific logistics cost containment metrics within the supply chain functions.

Other Strategic Objectives

In addition to reviewing the financial growth and operating performance results, the board of directors of our general partner reviewed individual performance relative to key strategic opportunities established at the beginning of the year for the named executive officers based on recommendations from the Chief Executive Officer.

The board of directors of our general partner determined that, due to below threshold performance on the financial metrics of Adjusted EBITDA and TUR, Messrs. Rasmus and Preston and Ms. Fulton would not receive 2018 short-term cash incentive payouts.

Long-Term Incentive Compensation

In connection with our initial public offering, the board of directors of our general partner adopted a long-term incentive plan in August 2012 which was amended and restated and superseded by the LTIP, effective September 21, 2016 for employees, officers, consultants and directors of our general partner and its affiliates, including Hi-Crush Services LLC, who perform services for us. All Hi-Crush Services LLC employees and each of our named executive officers, are eligible to participate in the LTIP. The LTIP provides for the grant of restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights, other unit-based awards and unit awards.

In December 2018, the board of directors of our general partner approved a long-term incentive award for Mr. Rasmus equal to 270% of base salary to be granted in both PPUs (50% of value) and TPUs (50% of value). The board also approved long-term incentive awards for Ms. Fulton and Messrs. Skolos and Barker of both PPUs (50% of value) and TPUs (50% of value). To determine the number of PPUs or TPUs to be granted to each named executive officer in 2018, we determined the dollar amount of long-term incentive compensation that we wanted to provide, and then granted the number of PPUs or TPUs that had a fair market value equal to that amount on the date prior to the grant date. For our named executive officers, long-term incentive award targets were established as a percentage of base salary (which reflects position and level of responsibility), with reference to the BDO study data for individuals in comparable positions.

The actual 2018 long-term incentive award values granted, expressed as a percentage of base salary and the number of PPUs and TPUs awarded on December 21, 2018, were as follows:

Name and Principal Position	2018 Long-Term Incentive Award Value (a)	2018 PPUs Awarded (b)	2018 TPUs Awarded
Robert E. Rasmus, Chief Executive Officer	270% of base salary	225,000	225,000
Laura C. Fulton, Chief Financial Officer	200% of base salary	101,389	101,389
Mark C. Skolos, General Counsel, Chief Compliance Officer and Secretary	175% of base salary	81,424	81,424
William E. Barker, Principal Strategy Officer	165% of base salary	59,583	59,584

(a) Award value is delivered 50% in PPUs and 50% in TPUs.

(b) Represents 100% of the PPUs awarded to the named executive officer. As discussed below, depending on the Partnership’s performance over a three-year period, between 0% and 200% of the performance units will vest.

The TPUs vest 50% on the second anniversary of the date of grant and 50% on the third anniversary of the date of grant.

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The number of PPUs that will vest will range from 0% to 200% of the number of initially granted PPUs and is dependent on the Partnership’s TUR, over a three-year performance period compared to the TUR of each entity in a newly established performance peer group. The newly established peer group of 44 companies includes sand producers, E&P operators, and oilfield and energy services and sand logistics companies with similarity to our business in terms of budget and capital needs, yield orientation, and supply chain services and cycle times. The performance peer group of companies includes:

Apergy Corporation	Nabors Industries Ltd.
Basic Energy Services, Inc.	Newfield Exploration Company
C&J Energy Services, Inc.	Newpark Resources, Inc.
Cactus, Inc.	Oasis Petroleum Inc.
Calfrac Well Services Ltd.	Patterson-UTI Energy, Inc.
Callon Petroleum Company	PDC Energy, Inc.
Centennial Resource Development, Inc.	Pioneer Energy Services Corp.
Cimarex Energy Co.	ProPetro Holding Corp.
Concho Resources Inc.	QEP Resources, Inc.
Covia Holdings Corporation	Range Resources Corporation
Diamondback Energy, Inc.	RPC, Inc.
Eagle Materials Inc.	Schlumberger Limited
Emerge Energy Services LP	Select Energy Services, Inc.
Energen Corporation	SM Energy Company
Forum Energy Technologies, Inc.	Solaris Oilfield Infrastructure, Inc.
FTS International, Inc.	Southcross Energy Partners, L.P.
Halliburton Company	Superior Energy Services, Inc.
Helmerich & Payne, Inc.	U.S. Silica Holdings, Inc.
Keane Group, Inc.	Unit Corporation
Key Energy Services, Inc.	Weatherford International plc
Liberty Oilfield Services Inc.	Whiting Petroleum Corporation
Matador Resources Company	WPX Energy, Inc.

For the 2018 PPUs, TUR captures both price appreciation (or depreciation) and cash distributions over the performance period. TUR is calculated as the difference between a) the "Beginning Price" (i.e,. the average closing price per unit for the first 90 days of the performance period) and b) the "Ending Price" (i.e., the average closing price per unit for the last 90 days of the performance period plus the "Aggregate Distribution Amount" (i.e., defined as the sum of all dividends and distributions paid with respect to a unit during the performance period)). In order for any portion of the PPUs to vest, our TUR ranking among the companies in the peer group over the performance period must be at least in the 25^th percentile, with the payout determined as follows using straight-line interpolation between the amounts set forth below. In addition, the board of directors of our general partner has discretion to increase or decrease the number of phantom units earned by up to 20%.

TUR Ranking (Percentile Ranking vs Peer Group)	Percentage of Target PPUs that Vest
Below 25th Percentile	—%
25th Percentile	50%
50th Percentile	100%
75th Percentile	200%

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Each PPU represents the right to receive, upon vesting, one common unit representing limited partner interests in the Partnership. The PPUs are also entitled to forfeitable distribution equivalent rights ("DERs"), which accumulate during the performance period and are paid in cash on the date of settlement. The amount paid on the DERs will equal the quarterly distributions actually paid on the underlying securities during the performance period. Except as otherwise provided in a named executive officer’s employment agreement as described under "Potential Payments Upon Termination or a Change in Control" below, termination of employment for any reason will result in the forfeiture of any unvested units and unpaid DERs. We believe that utilizing total unitholder return as the long-term performance measure for these awards provides incentive for the continued growth of our operating footprint and distributions to unitholders. The PPUs will vest if the named executive officer continuously provides services to the Partnership from the date of grant until the end of the performance period.

Second 2017 Unit Purchase Program

During 2017, the board of directors of our general partner approved the adoption of the Hi-Crush Partners LP Second 2017 Unit Purchase Program (the "Second 2017 UPP") offered under the LTIP as a purchase right for units. The Second 2017 UPP provides participating directors and employees, including the named executive officers, the opportunity to purchase common units representing limited partner interests of the Partnership at a discount. Employees contribute to the Second 2017 UPP through payroll deductions not to exceed 50% of such employee’s eligible compensation during the applicable offering period. Directors contribute to the Second 2017 UPP through cash contributions not to exceed $225,000 in the aggregate. 

On September 14, 2017, Messrs. Rasmus, Skolos and Barker and Ms. Fulton were granted the right to purchase common units on November 15, 2018 at $7.82 per common unit under the Second 2017 UPP. Mr. Preston was granted the right to purchase common units on November 15, 2018 at $11.60 per common unit upon his enrollment in the Second 2017 UPP on May 14, 2018. The offering period under the Second 2017 UPP ended on November 15, 2018, at which time the purchase date price was less than the election price. As a result, all contributions were returned to the participants (including the named executive officers) and no common units were purchased under the Second 2017 UPP.

Incentive Profits Interests

Pursuant to their employment agreements, each of Ms. Fulton and Mr. Skolos were previously granted a 0.75% profits interest and 0.25% profits interest, respectively, in our previous sponsor entitling them to receive 0.75% and 0.25%, respectively, of any net distributions made by our sponsor after the capital members of the sponsor had received aggregate distributions from our sponsor above applicable threshold amounts for each executive officer. During the year ended December 31, 2018, Ms. Fulton and Mr. Skolos were paid $298,491 and $99,497, respectively, prior to the Sponsor Contribution on October 21, 2018. All profits interest payments were a distribution from our sponsor, and the Partnership did not reimburse our sponsor under the Services Agreement for any portion of profits interest payments made by our sponsor.

Benefits

The Partnership does not maintain a defined benefit or pension plan for our named executive officers because it believes such plans primarily reward longevity rather than performance. Hi-Crush Services provides benefits to all of its employees that includes health, dental, vision, basic term life insurance, personal accident insurance and short and long-term disability coverage. Employees provided to us under the Services Agreement, including our named executive officers, are entitled to the same basic benefits. For the year ended December 31, 2018, Hi-Crush Services provided a 100% dollar-for-dollar matching contribution under the 401(k) plan on the first 2% of eligible compensation contributed to the plan and a 50% matching contribution on the next 4% of eligible compensation contributed to the plan, up to $11,000. The 401(k) matching contribution vests in four installments with the first 25% vesting upon completion of one year of service and an additional 25% vesting each year thereafter.

Risk Assessment Related to our Compensation Structure

We believe that the compensation plans and programs for our named executive officers, as well as our other employees, are appropriately structured and are not reasonably likely to result in material risk to the Partnership. We believe these compensation plans and programs are structured in a manner that does not promote excessive risk-taking that could harm the value of the Partnership or reward poor judgment. We also believe that compensation has been allocated among base salary and short and long-term compensation in such a way that does not encourage excessive risk-taking. Under our STI, annual cash incentives are provided to our executives to promote achievement of the Partnership’s short-term strategic objectives. The Partnership awards performance phantom limited partner units, which represent the right to receive upon vesting one common unit representing limited partner interests in the Partnership, rather than awarding unit options because the phantom units retain value even in a depressed market so that employees are less likely to take unreasonable risks to get, or keep, options "in-the-money." Finally, the time-based graded vesting over three years for the Partnership’s long-term incentive awards ensures that the interests of employees align with those of the unitholders of the Partnership for the long-term performance of the Partnership.

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Tax and Accounting Implications of Equity-Based Compensation Arrangements

Deductibility of Executive Compensation

We are currently a partnership and not a corporation for U.S. federal income tax purposes. Therefore, the compensation paid to our named executive officers in fiscal 2018 is not subject to the deduction limitations under Section 162(m) of the Internal Revenue Code.

Accounting for Unit-Based Compensation

For unit-based compensation arrangements, including equity-based awards (TPUs and PPUs) issued to our named executive officers, we record compensation expense over the vesting period of the awards, as discussed further in Note 14 to our consolidated financial statements.

Board of Directors Report

The board of directors of our general partner has reviewed and discussed with management the "Compensation Discussion and Analysis" presented above. The member of management with whom the board of directors of our general partner had discussions is the Chief Executive Officer. In addition, the board of directors of our general partner engaged the services of BDO, an executive compensation consulting firm, to conduct a study in 2018 to assist us in establishing overall compensation packages for our executives. Based on this review and discussion, we recommended that the "Compensation Discussion and Analysis" referred to above be included in this Annual Report on Form 10-K for the year ended December 31, 2018.

Board of Directors

John F. Affleck-Graves

John Kevin Poorman

Robert E. Rasmus

Joseph C. Winkler III

The foregoing report shall not be deemed to be incorporated by reference by any general statement or reference to this Annual Report on Form 10-K into any filing under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended, except to the extent that we specifically incorporate this information by reference, and shall not otherwise be deemed filed under those Acts.

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Compensation Tables

Summary Compensation Table

The following table shows the compensation paid or otherwise awarded to our fiscal year 2018 named executive officers for services rendered to us and our subsidiaries during fiscal years 2018, 2017 and 2016, as applicable.

Name and Principal Position	Year	Salary ($)	Equity Awards ($)(a)	Non-Equity Incentive Plan Compensation ($)(b)	All Other Compensation ($)(c)	Total ($)
Robert E. Rasmus Chief Executive Officer	2018	600,000	1,608,750	—	99,619	2,308,369
	2017	600,000	1,607,996	725,000	49,759	2,982,755
	2016	134,615	2,137,882	—	44,063	2,316,560
Laura C. Fulton Chief Financial Officer	2018	365,000	651,931	—	56,733	1,073,664
	2017	332,692	668,062	350,000	27,397	1,378,151
	2016	330,000	887,345	—	18,062	1,235,407
Mark C. Skolos General Counsel, Chief Compliance Officer and Secretary	2018	335,000	523,556	100,000	49,067	1,007,623
	2017	279,616	594,577	335,000	29,800	1,238,993
	2016	275,000	723,735	—	26,280	1,025,015
William E. Barker Principal Strategy Officer	2018	260,000	383,122	100,000	30,001	773,123
	2017	232,308	382,468	175,000	15,615	805,391
	2016	230,000	426,058	—	10,848	666,906
Scott J. Preston Chief Operating Officer	2018	262,291	466,550	—	981,048	1,709,889

(a) Equity award amounts reflect the aggregate grant date fair value of LTIP awards granted for the periods presented, computed in accordance with FASB ASC Topic 718. See Note 14 to our consolidated financial statements for additional assumptions underlying the value of the equity awards.

(b) Represents amounts paid according to the provisions of the short-term cash incentive plan then in effect. Amounts were earned in the fiscal year indicated but paid in the next fiscal year.

(c) Amounts in this column reflect the amount paid by our sponsor since 2016 that was reimbursable by us under the Services Agreement for matching 401(k) contributions, premiums paid for health and welfare benefits and coverage, cell phone and auto allowances, relocation benefits, separation payments, and cash dividends on vested equity awards. The following table provides details regarding the 2018 All Other Compensation:

Name	401(k) Matching Contributions ($)	Cash Dividends on Vested Equity Awards ($)	Relocation Expenses ($)	Relocation Expense Tax Gross-Up ($)	Cell Phone Allowances ($)	Auto Allowances ($)	Separation Payment ($)	Total ($)
Robert E. Rasmus	—	99,619	—	—	—	—	—	99,619
Laura C. Fulton	11,000	44,539	—	—	1,194	—	—	56,733
Mark C. Skolos	2,262	34,805	—	—	—	12,000	—	49,067
William E. Barker	8,600	20,207	—	—	1,194	—	—	30,001
Scott J. Preston	562	—	67,141	13,345	—	—	900,000	981,048

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Grants of Plan-Based Awards Table

The following supplemental compensation table shows compensation details on the value of plan-based incentive awards granted during 2018 to our named executive officers.  The table includes awards made during or for 2018.  The information in the table under the caption "Estimated Future Payouts Under Non-Equity Incentive Plan Awards" represents the threshold, target and maximum amounts payable under the short-term cash incentive plan for performance in 2018.  

		Estimated Future Payouts under Non-Equity Incentive Plan Awards (a)			Estimated Future Payouts under Equity Incentive Plan Awards (b)			Grant Date Fair Value of LTIP Awards ($)(c)
Name	Grant Date	Threshold ($)	Target ($)	Maximum ($)	Threshold (#)	Target (#)	Maximum (#)
Robert E. Rasmus
Short-term incentive plan	N/A	300,000	600,000	1,200,000	—	—	—	—
December 2018 PPU	12/21/2018	—	—	—	112,500	225,000	450,000	801,000
December 2018 TPU	12/21/2018	—	—	—	—	225,000	—	807,750
Laura C. Fulton
Short-term incentive plan	N/A	155,125	310,250	620,500	—	—	—	—
December 2018 PPU	12/21/2018	—	—	—	50,695	101,389	202,778	324,445
December 2018 TPU	12/21/2018	—	—	—	—	101,389	—	327,486
Mark C. Skolos
Short-term incentive plan	N/A	142,375	284,750	569,500	—	—	—	—
December 2018 PPU	12/21/2018	—	—	—	40,712	81,424	162,848	260,557
December 2018 TPU	12/21/2018	—	—	—	—	81,424	—	263,000
William E. Barker
Short-term incentive plan	N/A	65,000	130,000	260,000	—	—	—	—
December 2018 PPU	12/21/2018	—	—	—	29,792	59,583	119,166	190,666
December 2018 TPU	12/21/2018	—	—	—	—	59,584	—	192,456
Scott J. Preston
Short-term incentive plan	N/A	155,125	310,250	620,500	—	—	—	—
May 2018 TPU	5/16/2018	—	—	—	—	36,364	—	466,550

(a) Amounts shown represent the threshold, target and maximum payouts under the STI. If minimum levels of performance are not achieved, then the payout for one or more of the components of the STI may be zero. See "-Compensation Discussion and Analysis-Components of Executive Compensation-Annual Short-Term Cash Incentive" above for further discussion of these awards.

(b) The number of units shown represent units awarded under the LTIP. The PPUs awarded on December 21, 2018 will vest in their entirety after December 31, 2021 if the specified performance conditions are satisfied. If minimum levels of performance are not met, then none of the PPUs will vest. See "-Compensation Discussion and Analysis-Components of Executive Compensation-Long-Term Incentive Compensation" above for further discussion of these awards. The TPUs vest 50% on the second anniversary and 50% on the third anniversary of the grant date.

(c) Equity award amounts reflect the aggregate grant date fair value of LTIP awards granted for the periods presented, computed in accordance with FASB ASC Topic 718. See Note 14 to our consolidated financial statements for additional assumptions underlying the value of the equity awards.

Narrative Disclosure to the Summary Compensation Table and Grants of the Plan-Based Awards Table

A description of material factors necessary to understand the information disclosed in the tables above with respect to salaries, bonuses, equity awards, non-equity incentive plan compensation, and 401(k) plan contributions can be found in the compensation discussion and analysis that precedes these tables.

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Outstanding Equity Awards at Fiscal Year-End

The following are the outstanding equity awards for the named executive officers as of December 31, 2018:

	Outstanding LTIP Awards
Name	Equity Incentive Plan Awards: Unearned Units That Have Not Vested (a)	Equity Incentive Plan Awards: Market Value of Unearned Units That Have Not Vested ($) (a)(b)
Robert E. Rasmus	607,480	2,174,778
Laura C. Fulton	274,651	983,251
Mark C. Skolos	227,624	814,894
William E. Barker	156,534	560,392
Scott J. Preston	—	—

(a) PPUs were awarded in September 2016, December 2017 and December 2018 and vest in their entirety over a range of 0% to 200% within 45 days after December 31, 2018, 2019 and 2021, respectively, if and to the extent the specified performance conditions are satisfied. To determine the number of unearned units and the market value of such units in this table, the calculation of the number of PPUs granted that are expected to vest is based on assumed performance of 100% ("target") for the 2016 and 2017 and assumed performance of 50% ("threshold") for the 2018 PPUs. Our average TUR ranking over the performance period for the 2016 PPUs approximated the 48th percentile. Therefore 96% of the target performance units vested on February 1, 2019, as determined by the board of directors of our general partner. TPUs were awarded in September 2016, December 2017 and December 2018 to all then-employed named executive officers and vest 50% on the second anniversary and 50% on the third anniversary of the grant date.

(b) Value calculated based on the closing price at December 31, 2018 of our common units at $3.58.

Option Exercises and Units Vested

The following table provides information regarding units vesting for named executive officers during the year ended December 31, 2018:

	Unit Awards
Name	Number of Units  Acquired on Vesting	Value Realized on Vesting ($)(a)
Robert E. Rasmus	71,529	859,966
Laura C. Fulton	32,307	388,935
Mark C. Skolos	25,317	304,896
William E. Barker	14,573	175,307
Scott J. Preston	—	—

(a) The value of the units vesting was calculated by multiplying the number of units vesting by the closing market price of our common units on the date prior to vesting.

Pension Benefits

Currently, our general partner does not, and does not intend to, provide pension benefits to our named executive officers. Our general partner may change this policy in the future.

Nonqualified Deferred Compensation

Currently, our general partner does not, and does not intend to, sponsor or adopt a nonqualified deferred compensation plan. Our general partner may change this policy in the future.

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Potential Payments Upon Termination or a Change in Control

Aggregate Payments. The table below reflects the aggregate amount of payments and benefits that we believe our named executive officers would have received under their employment agreement and the Partnership’s LTIP upon certain specified termination of employment and/or a change in control events, in each case, had such event occurred on December 31, 2018. Details regarding individual plans and arrangements follow the table. The amounts below constitute estimates of the amounts that would be paid to our named executive officers upon each designated event, and do not include any amounts accrued through fiscal 2018 year-end that would be paid in the normal course of continued employment, such as accrued but unpaid salary and benefits generally available to all salaried employees. The actual amounts to be paid are dependent on various factors, which may or may not exist at the time a named executive officer is actually terminated and/or a change in control actually occurs. Therefore, such amounts and disclosures should be considered "forward-looking statements."

Name	Change in Control ($)	Termination without Cause or by Executive for Good Reason ($)	Termination with Cause or for Death or Disability ($)	Termination Due to Expiration of Term ($)
Robert E. Rasmus	2,174,778	750,000	—	—
Laura C. Fulton	983,251	182,500	—	182,500
Mark C. Skolos	814,894	167,500	—	167,500
William E. Barker	560,392	—	—	—
Scott J. Preston	—	1,310,045	—	—

Employment Agreements. Other than Mr. Barker, each of our named executive officers has entered into an employment agreement with Hi-Crush Services. The initial term of the each employment agreement is one year from the effective date of such agreement, with automatic extensions for additional one-year periods unless either party provides at least sixty days’ advance written notice of the intent to terminate the agreement.

The employment agreements contain severance provisions. Under the terms of the employment agreements, the employment of the named executive officer may be terminated by Hi-Crush Services with or without Cause (defined below), by the named executive officer for or without Good Reason (defined below), due to the named executive officer’s disability or death, or due to expiration of the term of the employment agreement.

Upon a termination by Hi-Crush Services for Cause, by the named executive officer without Good Reason, due to the named executive officer’s disability or death, or with respect to Mr. Rasmus due to expiration of the term of the employment agreement, the named executive officer is entitled to the following severance benefits: (i) payment of all accrued and unpaid base salary through the date of termination, (ii) reimbursement for all incurred but unreimbursed expenses entitled to reimbursement, and (iii) provision of any benefits to which the named executive officer is entitled pursuant to the terms of any applicable benefit plan or program (collectively, the "Accrued Obligations"). Under Ms. Fulton’s and Mr. Skolos’ employment agreement, upon a termination due to the expiration of the term, Ms. Fulton and Mr. Skolos shall be entitled to the following severance benefits: (i) payment of the Accrued Obligations and (ii) 50% of such named executive officer’s base salary, payable over the remainder of the term of the employment agreement in installments substantially similar to Hi-Crush Services salary payment practices.

Upon a termination by Hi-Crush Services without Cause or by the named executive officer for Good Reason, the named executive officer is entitled to the following severance benefits: (i) payment of the Accrued Obligations and (ii) (a) in the case of Mr. Rasmus, payment of an amount equal to $750,000 in a lump sum payment on the date that is 30 days after the date of termination, (b) in the case of Ms. Fulton and Mr. Skolos, the remainder of such employee’s base salary for the remaining term of the employment agreement, which in no event shall be less than 50% of such base salary, payable over the remainder of the term of the employment agreement in installments substantially similar to Hi-Crush Services salary payment practices, and (c) in the case of Mr. Preston, within the first two years of employment, 100% of base salary plus 100% of the annual short-term cash incentive and long-term incentive assuming target level, payable over the twelve months following termination in installments similar to the company’s salary payment practices plus accelerated vesting of a prorated amount of outstanding time-based vesting units, determined based on length of service during the vesting period. Payment of the additional payments are contingent upon the named executive officer’s execution and non-revocation of a general release of claims in favor of us. No named executive officer has any right to receive a "gross up" for any excise tax imposed by Section 4999 of the Code, or any federal, state or local income tax.

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Under the employment agreements, the following terms generally have the meanings set forth below:

• Cause means a named executive officer’s (i) conviction of, or entry of a guilty plea or plea of no contest with respect to, a felony or any other crime directly or indirectly involving the named executive officer’s lack of honesty or moral turpitude, (ii) drug or alcohol abuse for which the named executive officer fails to undertake and maintain treatment within five calendar days after requested by Hi-Crush Services, (iii) acts of fraud, embezzlement, theft, dishonesty or gross misconduct, (iv) material misappropriation (or attempted misappropriation) of any of our funds or property, or (v) a breach of the named executive officer’s obligations described under the employment agreement without cure. For Mr. Preston, Cause also includes the named executive officer’s (a) indictment for, or plea of guilty or nolo contendere to, an offense involving operation of a motor vehicle under the influence, (b) engagement in conduct that gives rise to a successful claim for sexual harassment or other conduct that violates Title VII of the 1964 Civil Rights Act or similar state law, and (c) engagement in conduct that gives rise to legitimate claims that we have violated federal, state or local criminal statutes or act.

• Good Reason means, without the named executive officer’s consent: (i) a material breach by Hi-Crush Services of its obligations under the employment agreement, (ii) any material diminution of the duties of the named executive officer, (iii) a reduction in the named executive officer’s base salary, other than pursuant to a proportionate reduction applicable to all senior executives or employees generally and the members of our sponsor’s board of directors, to the extent such board members receive board fees, or (iv) the relocation of the geographic location of the named executive officer’s principal place of employment by more than 50 miles.

The following table reflects payments that would have been made under the named executive officer’s employment agreement in the event the named executive officer’s employment was terminated as of December 31, 2018.

Name	Termination without Cause or by Executive for Good Reason ($)	Termination with Cause or for Death or Disability ($)	Termination Due to Expiration of Term ($)
Robert E. Rasmus	750,000	—	—
Laura C. Fulton	182,500	—	182,500
Mark C. Skolos	167,500	—	167,500
William E. Barker	—	—	—
Scott J. Preston	1,310,045	—	—

Performance Phantom Unit Grants under the LTIP. Each of our named executive officers, excluding Mr. Preston, held PPUs under our form of performance-based phantom unit award agreement (the "PPU Award Agreement") and the LTIP as of December 31, 2018. If a Change in Control occurs and the named executive officer has remained continuously employed by us from the date of grant to the date upon which such Change in Control occurs, then upon such Change of Control all forfeiture restrictions shall lapse and the performance period shall be deemed to end on the date of such Change of Control, with the actual performance calculated based on such shortened performance period.

Time-Based Phantom Unit Grants under the LTIP. If a Change in Control occurs and the named executive officer has remained continuously employed by us from the date of grant to the date upon which such Change in Control occurs, then upon such Change of Control, all forfeiture restrictions shall lapse and the TPUs become 100% vested.

The following terms generally have the following meanings for purposes of the LTIP and PPU Award Agreement:

• Affiliate means, with respect to any person, any other person that directly or indirectly through one or more intermediaries controls, is controlled by or is under common control with, the person in question. As used herein, the term "control" means the possession, direct or indirect, of the power to direct or cause the direction of the management and policies of a person, whether through ownership of voting securities, by contract or otherwise.

• Change of Control means, and shall be deemed to have occurred upon one or more of the following events: (i) any "person" or "group" within the meaning of those terms as used in Sections 13(d) and 14(d)(2) of the Exchange Act, other than members of the general partner, the Partnership, or an Affiliate of either the general partner or the Partnership, shall become the beneficial owner, by way of merger, consolidation, recapitalization, reorganization or otherwise, of 50% or more of the voting power of the voting securities of the general partner, (ii) the limited partners of the general partner or the Partnership approve, in one transaction or a series of transactions, a plan of complete liquidation of the general partner or the Partnership, (iii) the sale or other disposition by either the general partner or the Partnership of all or substantially all of its assets in one or more transactions to any Person other than an Affiliate, or (iv) the general partner or an Affiliate of the general partner or the Partnership ceases to be the general partner of the Partnership;

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The following table reflects amounts that would have been received by each of the named executive officers under the LTIP and related PPUs in the event there was a Change in Control as of December 31, 2018. The amounts reported below assume that the price per unit of our common units was $3.58, which was the closing price per unit of our common stock on December 31, 2018.

Name and Principal Position	Change in Control ($) (a)
Robert E. Rasmus, Chief Executive Officer	1,617,587
Laura C. Fulton, Chief Financial Officer	740,095
Mark C. Skolos, General Counsel, Chief Compliance Officer and Secretary	617,766
William E. Barker, Principal Strategy Officer	419,191

(a) Amounts reported relate to the PPUs awarded in September 2016, December 2017 and December 2018, which vest in their entirety over a range of 0% to 200% within 45 days after December 31, 2018, 2019 and 2021, respectively, if the specified performance conditions are satisfied. To determine the number of unearned units and the market value of such units, the calculation of the number of PPUs granted in September 2016, December 2017 and December 2018 that are expected to vest is based on assumed actual performance as of December 31, 2018 of 96%, 52% and 0%, for 2016, 2017 and 2018, respectively. The amounts also include the value of the TPUs which were granted in September 2016, December 2017 and December 2018.

CEO Pay Ratio

As required by Section 953(b) of the Dodd-Frank Wall Street Reform and Consumer Protection Act, and Item 402(u) of Regulation S-K, we are providing the following information about the relationship of the annual total compensation of our employees and the annual total compensation of Robert E. Rasmus, our Chief Executive Officer ("CEO"). Our independent compensation consultants assisted us in the calculation of this ratio.

For 2018, our last completed fiscal year:

• The median of the annual total compensation of all employees of our company (other than the CEO) was $79,785; and

• The annual total compensation of Mr. Rasmus, as reported in the Summary Compensation Table included within this Annual Report on Form 10-K, was $2,308,369.

• Based on this information, for 2018 the ratio of the annual total compensation of our CEO to the median of the annual total compensation of all employees ("CEO Pay Ratio") was reasonably estimated to be 29 to 1.

To calculate the CEO Pay Ratio we must identity the median of the annual total compensation of all our employees, as well as to determine the annual total compensation of our median employee and our CEO. To these ends, we took the following steps:

• We determined that, as of December 31, 2018, our employee population consisted of approximately 700 individuals. This population consisted of our full-time, part-time, and temporary employees.

• We used a consistently applied compensation measure to identify our median employee of comparing the amount of gross earnings paid in 2018. We identified our median employee by consistently applying this compensation measure to all of our employees included in our analysis. For individuals hired after January 1, 2018 that were included in the employee population, we calculated these compensation elements on an annualized basis. We did not make any cost of living adjustments in identifying the median employee.

After we identified our median employee, we combined all of the elements of such employee’s compensation for the 2018 year in accordance with the requirements of Item 402(c)(2)(x) of Regulation S-K, resulting in annual total compensation of $79,785. With respect to the annual total compensation of our CEO, we used the amount reported in the "Total" column of our 2018 Summary Compensation Table included in this Annual Report on Form 10-K.

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Director Compensation

The executive officers of our general partner who also serve as directors of our general partner do not receive additional compensation for their services as a director of our general partner. The directors who served on the board of directors of our general partner who resigned on October 21, 2018 in connection with the Sponsor Contribution did not receive compensation for their services as directors. The table below sets forth the annual compensation earned during 2018 by the non-executive directors of our general partner.

Director	Fees Earned or Paid in Cash ($) (a)	Unit Awards ($) (b)	All Other Compensation ($)		Total ($)
John F. Affleck-Graves	—	114,075	—		114,075
Jefferies V. Alston, III (c)	—	—	18,760	(d)	18,760
John R. Huff (e)	—	95,060	—		95,060
John Kevin Poorman	—	114,075	—		114,075
Joseph C. Winkler III	—	142,597	—		142,597

(a) Similar to 2017, during 2018 each independent director received 100% of their annual and committee retainers in grants of partnership units. In 2019, the independent directors will earn approximately two-thirds of their total compensation in grants of partnership units and one-third in cash. Director compensation is comprised of a $100,000 annual retainer, a committee member retainer for service on each committee ($10,000) and a committee chairman retainer for service on each committee ($25,000). Equity grants will be awarded annually free of restrictions each January and the cash portion will be paid quarterly.

(b) Equity award amounts reflect the aggregate grant date fair value of awards granted, computed in accordance with FASB ASC Topic 718.

(c) Mr. Alston resigned from the board of directors of our general partner on October 21, 2018.

(d) Represents amounts earned in 2018 under Mr. Alston's Separation and Consulting Agreement with the Partnership, the general partner and the sponsor.

(e) Mr. Huff resigned from the board of directors of our general partner on August 23, 2018.

As discussed in "Compensation Discussion and Analysis-Components of Executive Compensation-Other Compensation-Second 2017 Unit Purchase Program" above, directors may contribute to the Second 2017 UPP through cash contributions not to exceed $225,000 in the aggregate.  On September 14, 2017, each non-employee director participating in the Second 2017 UPP was granted the right to purchase, on November 15, 2018 at $7.82 per common unit. The offering period under the Second 2017 UPP ended on November 15, 2018, at which time the purchase date price was less than the election price. As such, all contributions were returned to the directors and no common units were purchased under the Second 2017 UPP.

Compensation Committee Interlocks and Insider Participation

None of the directors or executive officers of our general partner served as members of the compensation committee or board of directors of another entity that has or had an executive officer who served as a member of the board of directors of our general partner during 2018. Our general partner’s board of directors is not required to maintain, and does not maintain, a compensation committee. In addition, as previously noted, other than for equity-based awards under our LTIP, we do not directly employ or compensate the executive officers of our general partner. Rather, under the Services Agreement, we reimburse Hi-Crush Services and its affiliates for, among other things, the allocable expenses incurred in compensating our general partner’s executive officers. Mr. Rasmus, who is a member of the board of directors of our general partner, is also an executive officer of our general partner.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS

The following table sets forth the beneficial ownership of our common units issued and outstanding as of February 14, 2019 for:

• our general partner;

• beneficial owners of 5% or more of our common units;

• each director and named executive officer of our general partner; and

• all of our general partner's directors and executive officers as a group.

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Name of Beneficial Owner (a)	Common Units Beneficially Owned	Percentage of Common Units Beneficially Owned
Hi-Crush GP LLC	—	—	%
Robert E. Rasmus (b)	4,243,328	4.2	%
Laura C. Fulton	354,019	*
Mark C. Skolos	131,567	*
William E. Barker	19,588	*
Scott J. Preston (c)	307	*
John F. Affleck-Graves	87,320	*
John Kevin Poorman	64,559	*
Joseph C. Winkler III	99,072	*
All executive officers and directors as a group (8 persons)	4,999,760	4.9	%

*  Less than one percent

(a) The address for each of Robert E. Rasmus, Laura C. Fulton, Mark C. Skolos, William E. Barker, John F. Affleck-Graves, John Kevin Poorman and Joseph C. Winkler III is 1330 Post Oak Blvd, Suite 600, Houston, Texas 77056.

(b) Includes 500 common units owned by the reporting person’s son. Mr. Rasmus disclaims beneficial ownership of the 500 common units held by his son.

(c) Mr. Preston was appointed Chief Operating Officer of our general partner effective April 2, 2018. Effective December 12, 2018, Mr. Preston was no longer employed by the company. The number of common units beneficially owned by Mr. Preston is based on the Form 3 which was filed with the SEC on April 5, 2018.

Equity Compensation Plan Information

The following table sets forth information as of December 31, 2018 with respect to compensation plans under which our equity securities are authorized for issuance.

	(1) Number of  Units to be Issued Upon  Exercise of Outstanding Unit Options and Rights		(2) Weighted  Average Exercise Price Of Outstanding  Unit Options and Rights		(3) Number of  Units Remaining  Available For Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column (1))(c)
Plan Category
Equity compensation plans approved by unitholders:
First Amended and Restated Long-Term Incentive Plan (a)	2,390,138	(b)	—		840,915
Total for equity compensation plans	2,390,138		$	—	840,915

(a) The Partnership’s Long-Term Incentive Plan was adopted by our general partner in August 2012 in connection with our IPO and contemplated the issuance or delivery of up to 1,364,035 common units to satisfy awards under the plan. The previous Long-Term Incentive Plan was superseded by the LTIP which was approved by our common unitholders, which, among other things, provided for an increase in the number of common units of the Partnership reserved and available for delivery with respect to awards under the LTIP by 2,700,000 common units to an aggregate of 4,064,035 common units, effective as of September 21, 2016.

(b) Represents TPUs and PPUs granted under the LTIP, assuming the target distribution at the time of vesting. Payment with respect to the outstanding equity-settled performance unit awards range from 0% to 200% of the target distribution depending on performance actually attained, with a maximum number of 1,495,840 units being potentially issuable under the LTIP. There is no exercise price applicable to these awards.

(c) Includes units that may be issued in payment of the outstanding equity-settled performance phantom unit awards reported in column (1) if and to the extent such payment exceeds the target distribution amount reported in column (1) with respect to such awards.

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On January 14, 2019, the Partnership issued 62,184 common units to certain directors. Any units awarded after December 31, 2018 are not included in the Equity Compensation Plan Information table above, which provides information as of December 31, 2018.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Certain of the transactions and agreements disclosed in this section were determined by and among affiliated entities and, consequently, the terms of such transactions and agreements are not the result of arm’s length negotiations. These terms are not necessarily at least as favorable to the parties to these transactions and agreements as the terms that could have been obtained from unaffiliated third parties.

Agreements with Affiliates in Connection with the Acquisition of Hi-Crush Proppants LLC and Hi-Crush GP LLC

On October 21, 2018, the Partnership entered into a contribution agreement with our sponsor pursuant to which the Partnership acquired all of the then outstanding membership interests in the sponsor and the non-economic general partner interest in the Partnership, in exchange for 11,000,000 newly issued common units (the "Sponsor Contribution"). In connection with the acquisition, all of the outstanding incentive distribution rights representing limited partnership interests in the Partnership were canceled and extinguished and the sponsor waived any and all rights to receive contingent consideration payments from the Partnership or our subsidiaries pursuant to certain previously entered into contribution agreements to which it was a party.

Agreements with Affiliates in Connection with our Initial Public Offering

In connection with our IPO on August 16, 2012, we entered into certain agreements with our sponsor, as described in more detail below.

Omnibus Agreement

We entered into an omnibus agreement with affiliates of our general partner, including our sponsor, which addressed certain aspects of our relationship with them, including:

• our use of the name "Hi-Crush" and related marks;

• our payment of administrative services fees to our sponsor for general and administrative services; and

• certain indemnification obligations.

In connection with the Sponsor Contribution in October 2018, our sponsor ceased to control our general partner and, as a result, the omnibus agreement terminated.

Registration Rights Agreement

In connection with our IPO on August 16, 2012, we entered into a registration rights agreement with our sponsor (as amended the "Registration Rights Agreement"), pursuant to which we were required to register the sale of the following units held by our previous sponsor; the (i) common units issued (or issuable) to our sponsor pursuant to the contribution agreement, (ii) subordinated units and (iii) common units issuable upon conversion of the subordinated units or the Combined Interests (as defined in our partnership agreement) pursuant to the terms of the partnership agreement (together, the "Registrable Securities"). Under the Registration Rights Agreement, our sponsor had the right to request that we register the sale of Registrable Securities held by it, and our sponsor had the right to require us to make available shelf registration statements permitting sales of Registrable Securities into the market from time to time over an extended period, subject to certain limitations. The Registration Rights Agreement also includes provisions dealing with indemnification and contribution and allocation of expenses. All of our Registrable Securities held by our sponsor and any permitted transferee were be entitled to these registration rights.

In accordance with the foregoing requirements, we filed registration statements on Form S-3 with the SEC on October 1, 2013 and December 2, 2016.

Other Transactions with Related Persons

During the years ended December 31, 2018, 2017 and 2016, the Partnership engaged in multiple construction projects and purchased equipment, machinery and component parts from various vendors that were represented by Alston Environmental Company, Inc. or Alston Equipment Company ("Alston Companies"), which regularly represent vendors in such transactions. The vendors in question paid a commission to the Alston Companies in an amount that is unknown to the Partnership. The sister of Mr. Alston, who was a director of our general partner until October 21, 2018, has an ownership interest in the Alston Companies. The Partnership has not paid any sum directly to the Alston Companies and Mr. Alston has represented to the Partnership that he received no compensation from the Alston Companies related to these transactions.

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Procedures for Review, Approval and Ratification of Transactions with Related Persons

The board of directors of our general partner has adopted policies for the review, approval and ratification of transactions with related persons and a written Code of Business Conduct and Ethics. Under our Code of Business Conduct and Ethics, a director is required to bring to the attention of the chief executive officer(s) or the board any conflict or potential conflict of interest that may arise between the director or any affiliate of the director, on the one hand, and us or our general partner on the other. The resolution of any such conflict or potential conflict should, at the discretion of the board in light of the circumstances, be determined by a majority of the disinterested directors. In determining whether to approve or ratify a transaction with a related party, the board of directors of our general partner will take into account, among other factors it deems appropriate, (1) whether the transaction is on terms no less favorable than terms generally available to an unaffiliated third party under the same or similar circumstances, (2) the extent of the related person’s interest in the transaction and (3) whether the interested transaction is material to the Partnership. Our partnership agreement contains detailed provisions regarding the resolution of conflicts of interest, as well as the standard of care the board of directors of our general partner must satisfy in doing so.

If a conflict or potential conflict of interest arises between our general partner or its affiliates, on the one hand, and us or our unitholders, on the other hand, the resolution of any such conflict or potential conflict will be addressed by the board of directors of our general partner in accordance with the provisions of our partnership agreement. At the discretion of the board in light of the circumstances, the resolution may be determined by the board in its entirety or by the conflicts committee meeting the definitional requirements for such a committee under our partnership agreement. We do not expect that our Code of Business Conduct and Ethics or any policies that the board of directors of our general partner will adopt will require the approval of any transactions with related persons by our unitholders.

Based on our code of business conduct and ethics, any executive officer is required to avoid conflicts of interest unless approved by the board of directors of our general partner.

In the case of any sale of equity by us in which an owner or affiliate of an owner of our general partner participates, our practice is to obtain approval of the board for the transaction. The board will typically delegate authority to set the specific terms to a pricing committee, consisting of the chief executive officer and one independent director. Actions by the pricing committee require unanimous approval.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Our general partner is responsible for the Partnership’s internal controls and the financial reporting process. The independent registered public accounting firm, Deloitte & Touche LLP ("Deloitte"), is responsible for performing independent audits of the Partnership’s consolidated financial statements and issuing an opinion on the conformity of those audited financial statements with United States generally accepted accounting principles. The audit committee monitors the Partnership’s financial reporting process and reports to the board of directors of our general partner on its findings.

The audit committee of the board of directors of our general partner selected and engaged Deloitte to audit our consolidated financial statements for the years ended December 31, 2018 and 2017. The board of directors of our general partner has adopted a policy for pre-approving the services and associated fees of the independent registered public accounting firm. Under this policy, the audit committee must pre-approve all services and associated fees provided to us by its independent registered public accounting firm, with certain exceptions described in the policy. All Deloitte services and fees in the years ended December 31, 2018 and 2017 were pre-approved by the board of directors of our general partner, as applicable.

Prior to 2017, the audit committee of the board of directors of our general partner selected and engaged PricewaterhouseCoopers LLP ("PwC") to audit our consolidated financial statements for the year ended December 31, 2016. As previously announced, on March 28, 2017 the audit committee of the board of directors of our general partner recommended and authorized a change in independent registered public accounting firm from PwC to Deloitte, which became effective upon the issuance of PwC's audit report on the Partnership's consolidated financial statements that give effect to the recasting of such financial statements resulting from a transaction under common control as previously reported by the Partnership on Form 8-K filed on March 21, 2017.

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The following table presents fees billed or expected to be billed for professional audit services and other services rendered to the Partnership by Deloitte for the years ended December 31, 2018 and 2017 and the aggregate fees billed by PwC for professional audit services and other services rendered to the Partnership during the subsequent interim period in 2017 before the change in auditors became effective:

	Year Ended December 31,
	2018		2017
(in thousands)	Deloitte		Deloitte		PwC
Audit Fees	$	539	$	520	$	—
All Other Fees (a)	—		—		135
Audit-Related Fees (b)	100		—		238
Tax Fees (c)	—		—		369
Total Fees paid	$	639	$	520	$	742

(a) Represents fees related to tax compliance and consulting.

(b) Represents fees related to offering documents.

(c) Represents fees related to tax return preparation.

The audit committee has established procedures for engagement of Deloitte to perform services other than audit, review and attest services. In order to safeguard the independence of Deloitte, for each engagement to perform such non-audit service, (a) management and Deloitte affirm to the audit committee that the proposed non-audit service is not prohibited by applicable laws, rules or regulations; (b) management describes the reasons for hiring Deloitte to perform the services; and (c) Deloitte affirms to the audit committee that it is qualified to perform the services. The audit committee has delegated to its chair its authority to pre-approve such services in limited circumstances, and any such pre-approvals are reported to the audit committee at its next regular meeting. All services provided by Deloitte in 2018 were audit-related and are permissible under applicable laws, rules and regulations and were pre-approved by the board of directors of our general partner in accordance with its procedures. In 2018, the board of directors of our general partner considered the amount of non-audit services provided by Deloitte in assessing its independence.

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PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a)(1) Financial Statements

The Report of Independent Registered Public Accounting Firm, our Consolidated Financial Statements, the accompanying Notes to the Consolidated Financial Statements, and the Financial Statement Schedule that are filed as part of this Annual Report on Form 10-K are set forth beginning on page F-1 immediately following the signature pages of this Annual Report on Form 10-K.

(a)(2) Financial Statement Schedules

Schedule II - Valuation and Qualifying Accounts

Schedule II is filed as part of this Annual Report on Form 10-K immediately following the Notes to the Consolidated Financial Statements referred to above. The other schedules have been omitted because they are either not applicable, not required or the information called for therein appears in the consolidated financial statements or notes thereto.

(a)(3) Exhibits

The following documents are filed as a part of this Annual Report on Form 10-K or incorporated by reference:

Exhibit  Number	Description
2.1***	Membership Interest Purchase Agreement, dated May 13, 2013, by and among the Partnership, the members of D & I Silica, LLC, and their respective owners (incorporated by reference to Exhibit 1.01 to the Registrant’s Current Report on Form 8-K, filed with the SEC on May 16, 2013; File No. 001-35630).
2.2***	Membership Interest Purchase Agreement, dated February 23, 2017, by and among Hi-Crush Partners LP, Permian Basin Sand Company, LLC, Permian Basin Sand Holdings, LLC, PRE Wildcat Holdings, LLC, the Sellers listed therein, and Platte River Equity III, L.P. (incorporated by reference to Exhibit 2.1 to the Registrant’s Quarterly Report on Form 10-Q, filed with the SEC on May 1, 2017; File No. 001-35630).
2.3***	Purchase and Sale Agreement, dated as of July 19, 2018, by and among Hi-Crush Canada Inc., Hi-Crush Canada Distribution Corp., and for the limited purposes set forth in Section 9.15, Hi-Crush Partners LP, and FB Industries Inc., 6446508 Manitoba Inc., The Henry and Gloria Friesen Family Trust (2013), Tyler Friesen, Mavis Doell, Tracy Friesen, Henry Friesen, Gloria Friesen and Jonathan Doell, and Jonathan Doell, in his capacity as Sellers’ representative. (incorporated by reference to Exhibit 2.1 to the Registrant’s Current Report on Form 8-K, filed with the SEC on July 23, 2018).
3.1	Certificate of Limited Partnership of Hi-Crush Partners LP (incorporated by reference to Exhibit 3.1 to the Registrant's Registration Statement on Form S-1, Registration No. 333-182574, filed with the SEC on July 9, 2012).
3.2	Third Amended and Restated Agreement of Limited Partnership of Hi-Crush Partners LP, dated October 21, 2018 (incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K, filed with the SEC on October 23, 2018; File No. 001-35630).
4.1	Registration Rights Agreement by and between Hi-Crush Partners LP and Hi-Crush Proppants LLC dated August 20, 2012 (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K, filed with the SEC on August 21, 2012; File No. 001-35630).
4.2	First Amendment to Registration Rights Agreement by and between Hi-Crush Partners LP and Hi-Crush Proppants LLC, dated January 31, 2013 (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K, filed with the SEC on February 5, 2013; File No. 001-35630).
4.3	Second Amendment to Registration Rights Agreement by and between Hi-Crush Partners LP and Hi-Crush Proppants LLC, dated August 31, 2016 (incorporated by reference to Exhibit 10.2 of the Registrant’s Current Report on Form 8-K, filed with the SEC on September 7, 2016; File No. 001-35630).
4.4	Third Amendment to Registration Rights Agreement by and between Hi-Crush Partners LP and the Contributor Parties, dated October 21, 2018 (incorporated by reference to Exhibit 4.1 of the Registrant’s Current Report on Form 8-K, filed with the SEC on October 23, 2018; File No. 001-35630).
4.5	Lockup and Registration Rights Agreement, dated March 3, 2017, by and among Hi-Crush Partners LP, Platte River Equity III, L.P., Platte River Equity III-A, L.P., Platte River Equity III-Affiliates, L.P., PBS PRE III-B Holdings, LLC, Steven Herron, Peter Melcher, and Mark Smiens (incorporated by reference to Exhibit 4.1 of the Registrant’s Current Report on Form 8-K, filed with the SEC on March 9, 2017; File No. 001-35630).
4.6	Indenture, dated as of August 1, 2018, by and among Hi-Crush Partners LP, the subsidiary-guarantors party thereto and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K, filed with the SEC on August 2, 2018).
4.7	Form of 9.500% Senior Note due 2026 (incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K, filed with the SEC on August 2, 2018).

90

Exhibit  Number	Description
10.1	Credit Agreement, dated as of August 1, 2018, among Hi-Crush Partners LP as borrower, JPMorgan Chase Bank, N.A. as administrative agent, ZB N.A. DBA Amegy Bank, as an issuing lender and the lenders party thereto from time to time named therein (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K, filed with the SEC on August 2, 2018).
10.2	First Amendment to Credit Agreement, dated October  18, 2018, by and among Hi-Crush Partners LP, as borrower, JPMorgan Chase Bank, N.A. as administrative agent and an issuing lender, and the lenders party thereto (incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K, filed with the SEC on October 23, 2018; File No. 001-35630).
10.3	Management Services Agreement dated effective August 16, 2012, among Hi-Crush Partners LP, Hi-Crush GP LLC and Hi-Crush Services LLC (incorporated by reference to Exhibit 10.2 to the Registrant’s Quarterly Report on Form 10-Q, filed with the SEC on November 13, 2012; File No. 001-35630).
10.4	Maintenance and Capital Spare Parts Agreement dated effective August 16, 2012, among Hi-Crush Partners LP, Hi-Crush GP LLC and Hi-Crush Proppants LLC (incorporated by reference to Exhibit 10.3 to the Registrant’s Quarterly Report on Form 10-Q, filed with the SEC on November 13, 2012; File No. 001-35630).
10.5	Contribution, Assignment and Assumption Agreement by and among Hi-Crush Partners LP, Hi-Crush GP LLC and Hi-Crush Proppants LLC, dated August 15, 2012 (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K, filed with the SEC on August 21, 2012; File No. 001-35630).
10.6	Contribution Agreement by and among Hi-Crush Partners LP, Hi-Crush Augusta LLC and Hi-Crush Proppants LLC, dated January 31, 2013 (incorporated by reference to Exhibit 2.1 to the Registrant’s Current Report on Form 8-K, filed with the SEC on February 5, 2013; File No. 001-35630).
10.7	Omnibus Agreement by and among Hi-Crush Partners LP, Hi-Crush GP LLC and Hi-Crush Proppants LLC, dated August 20, 2012 (incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K, filed with the SEC on August 21, 2012; File No. 001-35630).
10.8	First Amendment to Omnibus Agreement, among Hi-Crush Partners LP, Hi-Crush GP LLC and Hi-Crush Proppants LLC, dated January 31, 2013 (incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K, filed with the SEC on February 5, 2013; File No. 001-35630).
10.9	Contribution Agreement by and among Hi-Crush Proppants LLC, Hi-Crush Augusta Acquisition Co. LLC and Hi-Crush Partners LP, dated April 8, 2014 (incorporated by reference to Exhibit 2.1 to the Registrant's Current Report on Form 8-K, filed with the SEC on April 29, 2014; File No. 001-35630).
10.10	Contribution Agreement by and between Hi-Crush Proppants LLC and Hi-Crush Partners LP, dated August 9, 2016, (incorporated by reference to Exhibit 10.3 to the Registrant’s Quarterly Report on Form 10-Q, filed with the SEC on October 31, 2016; File No. 001-35630).
10.11	Contribution Agreement by and among Hi-Crush Proppants LLC, Hi-Crush Augusta Acquisition Co. LLC and Hi-Crush Partners LP, dated February 23, 2017 (incorporated by reference to Exhibit 10.2 to the Registrant’s Quarterly Report on Form 10-Q, filed with the SEC on May 1, 2017; File No. 001-35630).
10.12	Contribution Agreement by and among Hi-Crush Partners LP, Hi-Crush Proppants LLC, Hi-Crush Augusta Acquisition Co. LLC and the other parties thereto, dated October 21, 2018 (incorporated by reference to Exhibit 2.1 to the Registrant’s Current Report on Form 8-K, filed with the SEC on October 23, 2018; File No. 001-35630).
10.13†	Hi-Crush Partners LP First Amended and Restated Long-Term Incentive Plan, adopted as of September 21, 2016 (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K, filed with the SEC on January 10, 2017; File No. 001-35630).
10.14†	Form of Hi-Crush Partners LP First Amended and Restated Long-Term Incentive Plan Phantom Unit Award Agreement (Performance-Based Vesting) (incorporated by reference to Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q, filed with the SEC on August 2, 2017; File No. 001-35630).
10.15†	Form of Hi-Crush Partners LP First Amended and Restated Long-Term Incentive Plan Phantom Unit Award Agreement (Time-Based Vesting) (incorporated by reference to Exhibit 10.2 to the Registrant’s Quarterly Report on Form 10-Q, filed with the SEC on August 2, 2017; File No. 001-35630).
10.16†	Form of Hi-Crush Partners LP First Amended and Restated Long-Term Incentive Plan Phantom Unit Award Agreement (Time Based Vesting - Canadian Employees) (incorporated by reference to Exhibit 10.2 to the Registrant’s Quarterly Report on Form 10-Q, filed with the SEC on October 30, 2018; File No. 001-35630).
10.17†	Form of Hi-Crush Partners LP Unit Purchase Program Enrollment Agreement and Terms and Conditions (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K, filed with the SEC on December 17, 2015; File No. 001-35630).
10.18†	Form of Hi-Crush Partners LP Second 2017 Unit Purchase Program Enrollment Agreement and Terms and Conditions (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K, filed with the SEC on September 18, 2017; File No. 001-35630).

91

Exhibit  Number	Description
10.19†	Employment Agreement, dated May 25, 2011, between Hi-Crush Proppants LLC and Robert E. Rasmus (incorporated by reference to Exhibit 10.14 to the Registrant’s Registration Statement on Form S-1, Registration No. 333-182574, filed with the SEC on July 9, 2012).
10.20†	Letter Agreement, dated July 13, 2012, between Hi-Crush Proppants LLC and Robert E. Rasmus (incorporated by reference to Exhibit 10.19 to the Registrant’s Registration Statement on Form S-1/A, Registration No. 333-182574, filed with the SEC on July 25, 2012).
10.21†	Separation and Consulting Agreement, dated October 28, 2016, by and among Jefferies Alston, III, Hi-Crush Proppants LLC, Hi-Crush GP LLC, and Hi-Crush Partners LP (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K, filed with the SEC on October 31, 2016; File No. 001-35630).
10.22†	Management Services Agreement, dated May 25, 2011 between Red Oak Capital Management LLC and Hi-Crush Proppants LLC (incorporated by reference to Exhibit 10.18 to the Registrant’s Registration Statement on Form S-1/A, Registration No. 333-182574, filed with the SEC on July 25, 2012).
10.23†	Employment Agreement, dated April 2, 2018, by and between Hi-Crush Services LLC, Hi-Crush Partners LP, Hi-Crush Proppants LLC, and Scott J. Preston (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on From 8-K, filed with the SEC on April 2, 2018).
10.24†	Separation Agreement and Release, dated December 12, 2018, by and between Hi-Crush Services LLC, Hi-Crush Partners LP, Hi-Crush Proppants LLC, and Scott J. Preston.
10.25†	Employment Agreement, dated April 30, 2012, by and between Hi-Crush Proppants LLC and Laura C. Fulton.
10.26†	Employment Agreement, dated April 16, 2012, by and between Hi-Crush Proppants LLC and Mark Skolos.
21.1	List of Subsidiaries of Hi-Crush Partners LP
23.1	Consent of Deloitte & Touche, LLP
23.2	Consent of PricewaterhouseCoopers LLP
23.3	Consent of John T. Boyd Company
31.1	Certification pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 signed by the Principal Executive Officer, filed herewith.
31.2	Certification pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 signed by the Principal Financial Officer, filed herewith.
32.1	Statement Required by 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 signed by Principal Executive Officer, filed herewith. (1)
32.2	Statement Required by 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 signed by Principal Financial Officer, filed herewith. (1)
95.1	Mine Safety Disclosure Exhibit
101	Interactive Data Files- XBRL

(1) This document is being furnished in accordance with SEC Release Nos. 33-8212 and 34-47551.

† Compensatory plan or arrangement.

*    Parts of the exhibit have been omitted pursuant to a request for confidential treatment.

***    Pursuant to Item 601(b)(2) of Regulation S-K, the Partnership agrees to furnish supplementally a copy of any omitted exhibit or schedule to the SEC upon request.

ITEM 16. FORM 10-K SUMMARY

None.

92

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, on February 19, 2019.

HI-CRUSH PARTNERS LP
By:	Hi-Crush GP LLC, its general partner
By:	/s/ Laura C. Fulton
	Laura C. Fulton Chief Financial Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of the Registrant and in the capacities indicated on February 19, 2019.

Hi-Crush Partners LP (Registrant)

By: Hi-Crush GP LLC, its general partner

Name	Capacity
/s/ Robert E. Rasmus	Chief Executive Officer and Chairman of the Board (Principal Executive Officer)
Robert E. Rasmus
/s/ Laura C. Fulton	Chief Financial Officer (Principal Financial and Accounting Officer)
Laura C. Fulton
/s/ John F. Affleck-Graves	Director
John F. Affleck-Graves
/s/ John Kevin Poorman	Director
John Kevin Poorman
/s/ Joseph C. Winkler III	Director
Joseph C. Winkler III

93

HI-CRUSH PARTNERS LP

INDEX TO FINANCIAL STATEMENTS

	Page
Report of Independent Registered Public Accounting Firms	F-2
Consolidated Balance Sheets as of December 31, 2018 and 2017	F-4
Consolidated Statements of Operations for the years ended December 31, 2018, 2017 and 2016	F-5
Consolidated Statements of Comprehensive Income for the years ended December 31, 2018, 2017 and 2016	F-6
Consolidated Statements of Cash Flows for the years ended December 31, 2018, 2017 and 2016	F-7
Consolidated Statements of Partners' Capital for the years ended December 31, 2018, 2017 and 2016	F-9
Notes to Consolidated Financial Statements	F-10

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Unitholders and the Board of Directors of Hi-Crush Partners LP

Houston, Texas

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Hi-Crush Partners LP and subsidiaries (the “Partnership”) as of December 31, 2018 and 2017, the related consolidated statements of operations, cash flows, and partners’ capital for each of the two years in the period ended December 31, 2018 and the related notes and the schedule listed in the index appearing under Item 15(a)(2) (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2018, in conformity with accounting principles generally accepted in the United States of America.

The consolidated financial statements of the Company for the year ended December 31, 2016, before the effects of the adjustments to retrospectively apply the change in accounting discussed in Note 4 to the financial statements, were audited by other auditors whose report, dated February 21, 2017, expressed an unqualified opinion on those statements. We have also audited the adjustments to the 2016 consolidated financial statements to retrospectively apply the change in accounting for the acquisition of Hi-Crush Proppants LLC and Hi-Crush GP LLC in 2018, as discussed in Note 4 to the financial statements. Our procedures included detail testing the activity of Hi-Crush Proppants LLC and Hi-Crush GP LLC. In our opinion, such retrospective adjustments are appropriate and have been properly applied. However, we were not engaged to audit, review, or apply any procedures to the 2016 consolidated financial statements of the Company other than with respect to the retrospective adjustments, and accordingly, we do not express an opinion or any other form of assurance on the 2016 consolidated financial statements taken as a whole.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Partnership’s internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 19, 2019, expressed an unqualified opinion on the Partnership’s internal control over financial reporting.

Basis for Opinion

These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the Partnership’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

DELOITTE & TOUCHE LLP

Houston, Texas

February 19, 2019

We have served as the Partnership’s auditor since 2017.

F-2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of Hi-Crush GP LLC

and Unitholders of Hi-Crush Partners LP

In our opinion, the consolidated statements of operations, partners’ capital and cash flows for the year ended December 31, 2016, before (i) the effects of the adjustments to retrospectively reflect the transaction to acquire Hi-Crush Proppants LLC and Hi-Crush GP LLC described in Note 4, (ii) the Company’s retrospective adoption of the change in accounting for revenue from contracts with customers described in Note 15, and (iii) presentation of the consolidated statement of comprehensive income, present fairly, in all material respects, the results of operations and cash flows of Hi-Crush Partners LP and its subsidiaries for the year ended December 31, 2016 in conformity with accounting principles generally accepted in the United States of America (the 2016 financial statements before (i) the effects of the adjustments to retrospectively reflect the transaction to acquire Hi-Crush Proppants LLC and Hi-Crush GP LLC described in Note 4, (ii) the Company’s retrospective adoption of the change in accounting for revenue from contracts with customers described in Note 15, and (iii) presentation of the consolidated statement of comprehensive income are not presented herein). In addition, in our opinion, the financial statement schedule for the year ended December 31, 2016 present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements before the effects of the adjustments described above. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audit. We conducted our audit, before the effects of the adjustments described above, of these financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

We were not engaged to audit, review, or apply any procedures to the adjustments to retrospectively reflect the transaction to acquire Hi-Crush Proppants LLC and Hi-Crush GP LLC described in Note 4, reflect the Company’s retrospective adoption of the change in accounting for revenue from contracts with customers or the presentation of the consolidated statement of comprehensive income, and accordingly, we do not express an opinion or any other form of assurance about whether such adjustments and disclosures are appropriate and have been properly applied. Those adjustments and disclosures were audited by other auditors.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

February 21, 2017, except for the effects of the merger of entities under common control (the Hi-Crush Whitehall LLC and Other assets transaction) as discussed in Note 4 to the consolidated financial statements, as to which the date is May 1, 2017

F-3

HI-CRUSH PARTNERS LP

Consolidated Balance Sheets

(In thousands, except unit amounts)

	December 31,
	2018			2017 (a)
Assets
Current assets:
Cash	$	114,256		$	7,724
Accounts receivable, net (Note 3)	101,029			139,486
Inventories (Note 5)	57,089			44,272
Prepaid expenses and other current assets	13,239			4,969
Total current assets	285,613			196,451
Property, plant and equipment, net (Note 6)	1,031,188			900,010
Goodwill and intangible assets, net (Note 7)	71,575			8,416
Equity method investments (Note 8)	37,354			17,475
Other assets	8,108			5,877
Total assets	$	1,433,838		$	1,128,229
Liabilities, Equity and Partners' Capital
Current liabilities:
Accounts payable	$	71,039		$	48,289
Accrued and other current liabilities (Note 9)	61,337			33,450
Current portion of deferred revenues (Note 15)	19,940			4,399
Current portion of long-term debt (Note 10)	2,194			4,140
Total current liabilities	154,510			90,278
Deferred revenues (Note 15)	9,845			7,384
Long-term debt (Note 10)	443,283			194,462
Asset retirement obligations (Note 11)	10,677			10,179
Other liabilities (Note 12)	8,276			156
Total liabilities	626,591			302,459
Commitments and contingencies (Note 12)
Equity and partners' capital:
Limited partners interest, 100,874,988 and 89,009,188 units outstanding, respectively	811,477			1,239,282
Accumulated other comprehensive loss	(4,230		)	—
Total partners' capital	807,247			1,239,282
Non-controlling interest	—			(413,512		)
Total equity and partners' capital	807,247			825,770
Total liabilities, equity and partners' capital	$	1,433,838		$	1,128,229

(a) Financial information has been recast to include the financial position and results attributable to our sponsor and general partner. See Note 4.

See Notes to Consolidated Financial Statements.

F-4

HI-CRUSH PARTNERS LP

Consolidated Statements of Operations

(In thousands, except unit and per unit amounts)

	Year Ended December 31,
	2018			2017 (a)			2016 (a)(b)
Revenues (Note 15)	$	842,840		$	602,623		$	204,430
Cost of goods sold (excluding depreciation, depletion and amortization)	577,974			438,348			188,308
Depreciation, depletion and amortization	38,284			29,449			17,032
Gross profit (loss)	226,582			134,826			(910		)
Operating costs and expenses:
General and administrative expenses	59,328			43,667			36,807
Accretion of asset retirement obligations (Note 11)	498			458			430
Impairments and other operating expenses (Note 17)	2,765			865			34,025
Other operating income	—			(3,554		)	—
Income (loss) from operations	163,991			93,390			(72,172		)
Other income (expense):
Earnings from equity method investments (Note 8)	5,184			75			—
Interest expense	(25,347		)	(12,971		)	(20,853		)
Loss on extinguishment of debt	(6,233		)	(4,332		)	—
Net income (loss)	$	137,595		$	76,162		$	(93,025	)
Earnings (loss) per limited partner unit:
Basic	$	1.46		$	0.97		$	(1.64	)
Diluted	$	1.42		$	0.96		$	(1.64	)
Weighted average limited partner units outstanding:
Basic	91,248,042			86,518,249			49,567,268
Diluted	93,638,180			87,900,982			49,567,268
Distributions declared per limited partner unit	$	1.20		$	0.35		$	—

(a) Financial information has been recast to include the results attributable to our sponsor and general partner. See Note 4.

(b) Financial information has been recast to include the results attributable to Hi-Crush Whitehall LLC and Other Assets. See Note 4.

See Notes to Consolidated Financial Statements.

F-5

HI-CRUSH PARTNERS LP

Consolidated Statements of Comprehensive Income

(In thousands)

	Year Ended December 31,
	2018			2017 (a)		2016 (a)(b)
Net income (loss)	$	137,595		$	76,162	$	(93,025	)
Foreign currency translation adjustment	(4,230		)	—		—
Comprehensive income (loss)	$	133,365		$	76,162	$	(93,025	)

(a) Financial information has been recast to include the results attributable to our sponsor and general partner. See Note 4.

(b) Financial information has been recast to include the results attributable to Hi-Crush Whitehall LLC and Other Assets. See Note 4.

See Notes to Consolidated Financial Statements.

F-6

HI-CRUSH PARTNERS LP

Consolidated Statements of Cash Flows

(In thousands)

	Year Ended December 31,
	2018			2017 (a)			2016 (a)(b)
Operating activities:
Net income (loss)	$	137,595		$	76,162		$	(93,025	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation and depletion	38,775			29,872			17,616
Amortization of intangible assets	3,374			1,681			1,682
Loss on impairments of goodwill	—			—			33,745
Provision for doubtful accounts	—			—			8,236
Unit-based compensation to directors and employees	7,439			5,714			2,620
Amortization of loan origination costs into interest expense	1,164			2,022			3,678
Accretion of asset retirement obligations	498			458			430
Accrued interest converted to debt	—			528			2,112
(Gain) loss on disposal of property, plant and equipment	369			92			(357		)
Earnings from equity method investments	(5,184		)	(75		)	—
Loss on extinguishment of debt	6,233			4,332			—
Changes in operating assets and liabilities:
Accounts receivable	41,237			(86,652		)	(19,593		)
Inventories	1,556			(14,529		)	7,081
Prepaid expenses and other current assets	(6,670		)	(542		)	2,139
Other assets	(1,301		)	2,112			1,337
Accounts payable	(5,193		)	26,282			1,188
Accrued and other current liabilities	11,066			24,788			(773		)
Deferred revenues	6,372			11,783			—
Deferred rent	(27		)	(53		)	(48		)
Net cash provided by (used in) operating activities	237,303			83,975			(31,932		)
Investing activities:
Capital expenditures for property, plant and equipment	(141,546		)	(122,246		)	(45,714		)
Proceeds from sale of property, plant and equipment	3,064			8			1,403
Business acquisition, net of cash acquired	(34,960		)	—			—
Asset acquisition	—			(200,830		)	—
Equity method investments	(14,695		)	(7,168		)	(10,232		)
Restricted cash, net	—			5,116			2,390
Net cash used in investing activities	(188,137		)	(325,120		)	(52,153		)
Financing activities:
Proceeds from equity issuances, net	—			412,577			189,037
Transaction costs associated with equity issuances	—			—			3
Proceeds from issuance of long-term debt	450,000			198,000			17,000
Repayment of long-term debt	(203,378		)	(259,791		)	(136,401		)
Proceeds from insurance premium notes	4,153			3,156			2,442
Repayment of premium financing notes	(3,836		)	(2,713		)	(2,886		)
Loan origination costs	(12,067		)	(4,731		)	(138		)
Contributions (withdrawals) from unit purchase program participants	(438		)	438			111
Repurchase of common units	(9,426		)	(20,000		)	—
Redemption of common units	(70		)	—			—
Payment of accrued distribution equivalent rights	(410		)	(39		)	—
Distributions paid to members of Hi-Crush Proppants LLC	(39,516		)	(69,215		)	—
Distributions paid to limited partner unitholders	(127,645		)	(13,656		)	—
Net cash provided by financing activities	57,367			244,026			69,168
Effects of exchange rate on cash	(1		)	—			—
Net increase (decrease) in cash	106,532			2,881			(14,917		)
Cash at beginning of period	7,724			4,843			19,760
Cash at end of period	$	114,256		$	7,724		$	4,843

F-7

	Year Ended December 31,
	2018		2017 (a)		2016 (a)(b)
Non-cash investing and financing activities:
Increase (decrease) in accounts payable and accrued liabilities for additions to property, plant and equipment	$	26,333	$	2,253	$	(8,125	)
Increase in property, plant and equipment for asset retirement obligations	$	—	$	207	$	373
Debt financed capital expenditures	$	3,676	$	—	$	3,676
Estimated fair value of contingent consideration liability	$	8,147	$	—	$	—
Issuance of units for acquisitions	$	19,190	$	62,242	$	—
Issuance of units under unit purchase programs	$	—	$	1,576	$	—
Increase (decrease) in accrued distribution equivalent rights	$	1,860	$	45	$	(88	)
Cash paid for interest	$	6,224	$	10,950	$	17,175

(a) Financial information has been recast to include the financial position and results attributable to our sponsor and general partner. See Note 4.

(b) Financial information has been recast to include the financial position and results attributable to Hi-Crush Whitehall LLC and Other Assets. See Note 4.

See Notes to Consolidated Financial Statements.

F-8

HI-CRUSH PARTNERS LP

Consolidated Statements of Partners’ Capital

(In thousands)

	Limited Partner Capital			Accumulated Other Comprehensive Income (Loss)			Non-Controlling Interest			Total Equity and Partners Capital
Balance at December 31, 2015	$	340,719		$	—		$	(69,075	)	$	271,644
Issuance of 19,550,000 common units, net	189,037			—			—			189,037
Issuance of 103,377 common units to directors	453			—			—			453
Unit-based compensation expense	2,146			—			—			2,146
Forfeiture of distribution equivalent rights	88			—			—			88
Transaction costs associated with equity issuances (a)	—			—			3			3
Net loss (a)(b)	(93,025		)	—			—			(93,025		)
Balance at December 31, 2016	439,418			—			(69,072		)	370,346
Issuance of 23,575,000 common units, net	412,577			—			—			412,577
Issuance of 3,438,789 common units for asset acquisition	62,242			—			—			62,242
Issuance of 329,238 common units to directors and employees	2,144			—			—			2,144
Repurchase of 2,030,163 common units	(20,000		)	—			—			(20,000		)
Unit-based compensation expense	5,215			—			—			5,215
Distribution of 20,693,643 HCLP common units to members (a)	275,225			—			(275,225		)	—
Distributions to members of Hi-Crush Proppants LLC (a)	—			—			(69,215		)	(69,215		)
Distributions, including distribution equivalent rights	(13,808		)	—			—			(13,808		)
Forfeiture of distribution equivalent rights	107			—			—			107
Net income (a)	76,162			—			—			76,162
Balance at December 31, 2017	1,239,282			—			(413,512		)	825,770
Issuance of 1,279,328 common units for business acquisition	19,190			—			—			19,190
Issuance of 36,109 common units to directors	474			—			—			474
Repurchase of 753,090 common units	(9,426		)	—			—			(9,426		)
Redemption of 5,799 common units	(70		)	—			—			(70		)
Unit-based compensation expense	6,965			—			—			6,965
Distributions to members of Hi-Crush Proppants LLC (a)	—			—			(39,516		)	(39,516		)
Distributions, including distribution equivalent rights	(129,505		)	—			—			(129,505		)
Acquisition of Hi-Crush Proppants LLC and Hi-Crush GP LLC	(453,028		)	—			453,028			—
Other comprehensive loss	—			(4,230		)	—			(4,230		)
Net income	137,595			—			—			137,595
Balance at December 31, 2018	$	811,477		$	(4,230	)	$	—		$	807,247

(a) Financial information has been recast to include the financial position and results attributable to our sponsor and general partner. See Note 4.

(b) Financial information has been recast to include the financial position and results attributable to Hi-Crush Whitehall LLC and Other Assets. See Note 4.

See Notes to Consolidated Financial Statements.

F-9

HI-CRUSH PARTNERS LP

Notes to Consolidated Financial Statements

(Dollars in thousands, except unit and per unit amounts, or where otherwise noted)

1. Business and Organization

Hi-Crush Partners LP (together with its subsidiaries, the "Partnership," "we," "us" or "our") is a Delaware limited partnership formed on May 8, 2012. In connection with its formation, the Partnership issued a non-economic general partner interest to Hi-Crush GP LLC (the "general partner"), and a 100% limited partner interest to Hi-Crush Proppants LLC (the "sponsor"), its organizational limited partner. The Partnership is a fully integrated, strategic provider of proppant and logistics solutions to the North American petroleum industry. We provide mine-to-wellsite logistics services that optimize proppant supply to customers in all major oil and gas basins in the United States, and own and operate multiple frac sand mining facilities and in-basin terminals. Our PropStream^® service, offering both container- and silo-based wellsite delivery and storage systems, provides the highest level of flexibility, safety and efficiency in managing the full scope and value of the proppant supply chain. 

On August 31, 2016, the Partnership acquired from its sponsor all of the outstanding membership interests in Hi-Crush Blair LLC ("Blair"), the entity that owned our sponsor's Blair facility (the "Blair Contribution").

On March 15, 2017, the Partnership acquired from its sponsor all of the outstanding membership interests in Hi-Crush Whitehall LLC ("Whitehall"), the entity that owned our sponsor’s Whitehall facility, the remaining 2.0% equity interest in Hi-Crush Augusta LLC ("Augusta"), and all of the outstanding membership interests in PDQ Properties LLC (together, the "Other Assets") (the "Whitehall Contribution").

On March 3, 2017, the Partnership completed an acquisition of Permian Basin Sand Company, LLC ("Permian Basin Sand"). With the acquisition of Permian Basin Sand, we acquired a 1,226-acre frac sand reserve, located near Kermit, Texas, strategically positioned in the Permian Basin.

On August 1, 2018, the Partnership completed the acquisition of FB Industries Inc. ("FB Industries"), a company engaged in the engineering, design and marketing of silo-based frac sand management systems.

On October 21, 2018, the Partnership entered into a contribution agreement with our sponsor pursuant to which the Partnership acquired all of the then outstanding membership interests in the sponsor and the non-economic general partner interest in the Partnership, in exchange for 11,000,000 newly issued common units (the "Sponsor Contribution"). In connection with the acquisition, all of the outstanding incentive distribution rights representing limited partnership interests in the Partnership were canceled and extinguished and the sponsor waived any and all rights to receive contingent consideration payments from the Partnership or our subsidiaries pursuant to certain previously entered into contribution agreements to which it was a party.

Refer to Note 4 - Acquisitions for additional disclosure regarding these acquisitions.

2. Basis of Presentation

The Sponsor Contribution, Blair Contribution and Whitehall Contribution were accounted for as transactions between entities under common control whereby the net assets of our sponsor and general partner and Blair, Whitehall and Other Assets were recorded at their historical cost. Therefore, the Partnership's historical financial information has been recast to combine our sponsor and general partner, Blair, Whitehall and Other Assets with the Partnership as if the combination had been in effect since inception of the common control. Refer to Note 4 - Acquisitions for additional disclosure regarding the Sponsor Contribution, Blair Contribution and Whitehall Contribution.

These financial statements have been prepared assuming the Partnership will continue to operate as a going concern. On a quarterly basis, the Partnership assesses whether conditions have emerged which may cast substantial doubt about the Partnership's ability to continue as a going concern for the next twelve months following the issuance of these financial statements.

F-10

HI-CRUSH PARTNERS LP

Notes to Consolidated Financial Statements

(Dollars in thousands, except unit and per unit amounts, or where otherwise noted)

3. Significant Accounting Policies

Use of Estimates

The preparation of the financial statements in conformity with accounting principles generally accepted in the United States of America ("GAAP") requires management to make estimates and assumptions that affect the reported amount of assets and liabilities and disclosure of contingent liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. The more significant estimates relate to purchase accounting allocations and valuations, estimates and assumptions for our mineral reserves and its impact on calculating our depreciation and depletion expense under the units-of-production depreciation method, assessing potential impairment of long-lived assets, estimating potential loss contingencies, inventory valuation, valuation of unit-based compensation, estimated fair value of contingent consideration in the future and the estimated cost of future asset retirement obligations. Actual results could differ from those estimates.

Cash and Cash Equivalents

Cash and cash equivalents consist of all cash balances and highly liquid investments with an original maturity of three months or less.

Accounts Receivable

Trade receivables relate to sales of frac sand and related services for which credit is extended based on the customer’s credit history and are recorded at the invoiced amount and do not bear interest. The Partnership regularly reviews the collectability of accounts receivable. When it is probable that all or part of an outstanding balance will not be collected, the Partnership establishes or adjusts an allowance as necessary generally using the specific identification method. Account balances are charged against the allowance after all means of collection have been exhausted and potential recovery is considered remote. As of each of December 31, 2018 and 2017, the Partnership maintained an allowance for doubtful accounts of $1,060. During the first quarter of 2016, the Partnership incurred bad debt expense of $8,236 which was primarily the result of a spot customer filing for bankruptcy.

Revenues recognized in advance of invoice issuance create assets referred to as "unbilled receivables." Any portion of our unbilled receivables for which our right to consideration is conditional on a factor other than the passage of time is considered a contract asset. These assets are presented on a combined basis with accounts receivable and are converted to trade receivables once billed.

Deferred Financing Charges

Certain direct costs incurred in connection with debt financing have been capitalized and are being amortized using the straight-line method, which approximates the effective interest method, over the life of the debt. Amortization expense is included in interest expense and was $1,164, $2,022 and $3,678 for the years ended December 31, 2018, 2017 and 2016, respectively.

Debt issuance costs related to a recognized debt liability are presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. Debt issuance costs associated with a revolving credit facility are maintained in other assets. In connection with the private placement of $450,000 aggregate principal amount of its 9.50% senior unsecured notes due 2026 (the "Senior Notes") and a senior secured revolving credit facility (the "ABL Credit Facility"), the Partnership incurred debt issuance costs of $12,067 that were capitalized. As of December 31, 2018 and 2017, the Partnership maintained unamortized debt issuance costs of $9,375 and $3,643 within long-term debt, respectively and $1,953 and $1,070 within other assets, respectively. Refer to Note 10 - Long-Term Debt for additional disclosure on our debt.

The following is a summary of future amortization expense associated with deferred financing charges:

For the years ending December 31,
2019	$	1,662
2020	1,662
2021	1,662
2022	1,662
2023	1,485
Thereafter	3,195
Total	$	11,328

F-11

HI-CRUSH PARTNERS LP

Notes to Consolidated Financial Statements

(Dollars in thousands, except unit and per unit amounts, or where otherwise noted)

Inventories

Sand inventory is stated at the lower of cost or net realizable value using the average cost method.

Inventory manufactured at our production facilities includes direct excavation costs, processing costs, overhead allocation, depreciation and depletion. Stockpile tonnages are calculated by measuring the number of tons added and removed from the stockpile. Tonnages are verified periodically by an independent surveyor. Costs are calculated on a per ton basis and are applied to the stockpile based on the number of tons in the stockpile.

Inventory transported for sale at our terminal facilities or at the blender includes the cost of purchased or manufactured sand, plus transportation and handling related charges.

Spare parts inventory includes critical spares, materials and supplies. We account for spare parts on a first-in, first-out basis, and value the inventory at the lower of cost or net realizable value. Detail reviews are performed related to the net realizable value of the spare parts inventory, giving consideration to quality, excessive levels, obsolescence and other factors.

Payments to third parties for silo systems and other equipment manufactured for sale to third parties is included in inventory as work-in-process until completed and ready for delivery to the customer, at which time it is classified as finished goods inventory.  Silo systems and equipment for sale to third parties is stated at the lower of cost or net realizable value using the average cost method.

Property, Plant and Equipment

Additions and improvements occurring through the normal course of business are capitalized at cost. When assets are retired or disposed of, the cost and the accumulated depreciation and depletion are eliminated from the accounts and any gain or loss is reflected in the Consolidated Statements of Operations. Expenditures for normal repairs and maintenance are expensed as incurred. Construction-in-progress is primarily comprised of machinery and equipment which has not been placed in service.

Mine development costs include engineering, mineralogical studies, drilling and other related costs to develop the mine, the removal of overburden to initially expose the mineral and building access ways. Exploration costs are expensed as incurred and classified as exploration expense. Capitalization of mine development project costs begins once the deposit is classified as proven and probable reserves.

Drilling and related costs are capitalized for deposits where proven and probable reserves exist and the activities are directed at obtaining additional information on the deposit or converting non-reserve minerals to proven and probable reserves and the benefit is to be realized over a period greater than one year.

Mining property and development costs are amortized using the units-of-production method on estimated measured tons in in-place reserves. The impact of revisions to reserve estimates is recognized on a prospective basis.

Capitalized costs incurred during the year for major improvement and capital projects that are not placed in service are recorded as construction-in-progress. Construction-in-progress is not depreciated until the related assets or improvements are ready to be placed in service. We capitalize interest cost as part of the historical cost of constructing an asset and preparing it for its intended use. These interest costs are included in the property, plant and equipment on the Consolidated Balance Sheet.

Fixed assets other than plant facilities and buildings associated with productive, depletable properties are carried at historical cost and are depreciated using the straight-line method over the estimated useful lives of the assets, as follows:

Computer equipment	3 years
Furniture and fixtures	7 years
Vehicles	5 years
Equipment	5-15 years
Rail spurs and asset retirement obligations	17-33 years
Rail and rail equipment	15-20 years
Transload facilities and equipment	15-25 years

Plant facilities and buildings associated with productive, depletable properties that contain frac sand reserves are carried at historical cost and are depreciated using the units-of-production method. Units-of-production rates are based on the amount of proved developed frac sand reserves that are estimated to be recoverable from existing facilities using current operating methods.

F-12

HI-CRUSH PARTNERS LP

Notes to Consolidated Financial Statements

(Dollars in thousands, except unit and per unit amounts, or where otherwise noted)

Impairment of Long-lived Assets

Recoverability of investments in property, plant and equipment, and mineral rights is evaluated annually, or more often if events or circumstances indicate the impairment of an asset may exist. Estimated future undiscounted net cash flows are calculated using estimates of proven and probable sand reserves, estimated future sales prices (considering historical and current prices, price trends and related factors) and operating costs and anticipated capital expenditures. Reductions in the carrying value of our investment are only recorded if the undiscounted cash flows are less than our book basis in the applicable assets.

Impairment losses are recognized based on the extent that the remaining investment exceeds the fair value, which is determined based upon the estimated future discounted net cash flows to be generated by the property, plant and equipment and mineral rights.

Management’s estimates of prices, recoverable proven and probable reserves and operating and capital costs are subject to certain risks and uncertainties which may affect the recoverability of our investments in property, plant and equipment. Although management has made its best estimate of these factors based on current conditions, it is reasonably possible that changes could occur in the near term, which could adversely affect management’s estimate of the net cash flows expected to be generated from its operating property. No impairment charges were recorded during the years ended December 31, 2018, 2017 and 2016.

Goodwill and Intangible Assets

Goodwill represents the excess of purchase price over the fair value of net assets acquired. The Partnership performs an assessment of the recoverability of goodwill during the third quarter of each fiscal year, or more often if events or circumstances indicate the impairment of an asset may exist. Our assessment of goodwill is based on qualitative factors to determine whether the fair value of the reporting unit is more likely than not less than the carrying value. An additional quantitative impairment analysis is completed if the qualitative analysis indicates that the fair value is not substantially in excess of the carrying value. The quantitative analysis determines the fair value of the reporting unit based on the discounted cash flow method and relative market-based approaches. During the year ended December 31, 2016, we recognized a $33,745 impairment loss of goodwill. The Partnership did not recognize any impairments for goodwill during the years ended December 31, 2018 and 2017. Refer to Note 17 - Impairments and Other Operating Expenses for additional disclosure regarding our goodwill impairment assessment.

The Partnership amortizes the cost of other intangible assets on a straight line basis over their estimated useful lives, ranging from 1 to 20 years. An impairment assessment is performed if events or circumstances occur and may result in the change of the useful lives of the intangible assets. The Partnership did not recognize any impairments for intangible assets during the years ended December 31, 2018, 2017 and 2016.

Equity Method Investments

The Partnership accounts for investments that it does not control but has the ability to exercise significant influence, using the equity method of accounting. Under this method, the investment is carried originally at cost, increased by any allocated share of the Partnership's net income and contributions made, and decreased by any allocated share of the Partnership's net losses and distributions received. The Partnership's allocated share of income and losses are based on the rights and priorities outlined in the equity investment agreement.

Contingent Consideration

Accounting standards require that contingent consideration be recorded at fair value at the date of acquisition and revalued during subsequent reporting dates under the acquisition method of accounting. The estimated fair value of contingent consideration is recorded as other liabilities on the Consolidated Balance Sheet. The estimate of fair value of a contingent consideration obligation requires subjective assumptions to be made regarding future business results, discount rates and probabilities assigned to various potential business result scenarios. Any adjustments to fair value are recognized in earnings in the period identified. Refer to Note 12 - Commitments and Contingencies for additional disclosure regarding contingent consideration.

Contingent consideration arrangements entered into in connection with acquisitions between entities under common control are valued at fair value at the date of acquisition and any differences between the original estimated fair value, and the actual resulting payments in the future are reflected as an equity adjustment to the deemed distributions associated with the acquisitions.

Asset Retirement Obligations

In accordance with Accounting Standards Codification ("ASC") 410-20, Asset Retirement Obligations, we recognize reclamation obligations when incurred and record them as liabilities at fair value. In addition, a corresponding increase in the carrying amount of the related asset is recorded and depreciated over such asset’s useful life. The reclamation liability is accreted to expense over the estimated productive life of the related asset and is subject to adjustments to reflect changes in value resulting from the passage of time and revisions to the estimates of either the timing or amount of the reclamation costs.

F-13

HI-CRUSH PARTNERS LP

Notes to Consolidated Financial Statements

(Dollars in thousands, except unit and per unit amounts, or where otherwise noted)

Revenue Recognition

As of January 1, 2018, we adopted the new Accounting Standards Update ("ASU") 2014-09, Revenue from Contracts with Customers (Topic 606), and all the related amendments to all contracts using the full retrospective method. The adoption of Topic 606 had no impact on our revenue recognition practices or impact to our Consolidated Financial Statements but required additional disclosures. Refer to Note 15 - Revenues for additional disclosure regarding revenues.

We generate frac sand revenues from the sale of raw frac sand that our customers purchase for use in the oil and natural gas industry. A substantial portion of our frac sand is sold to customers with whom we have long-term supply agreements, the current terms of which expire between 2020 and 2024. The agreements define, among other commitments, the volume of product that the Partnership must provide and the volume that the customer must purchase by the end of the defined periods. Pricing structures under our agreements are in many cases subject to certain contractual adjustments and consist of a combination of negotiated pricing and fixed pricing. These arrangements may undergo negotiations regarding pricing and volume requirements, which may occur in volatile market conditions. We also sell sand through individual purchase orders executed on the spot market, at prices and other terms determined by the existing market conditions as well as the specific requirements of the customer. We typically invoice our frac sand customers as the product is delivered and title transfers to the customer, with standard collection terms of net 30 days.

Frac sand sales revenues are recognized at the point in time following the transfer of control to the customer when legal title passes, which may occur at the production facility, rail origin, terminal or wellsite. Revenue recognition is driven by the execution and delivery of frac sand by the Partnership to the customer, which is initiated by the customer placing an order for frac sand, the Partnership accepting and processing the order, and the physical delivery of sand at the location specified by the customer. At that point in time, delivery has occurred, evidence of a contractual arrangement exists and collectability is reasonably assured.

Revenue from make-whole provisions in our customer contracts is recognized as other revenue at the end of the defined period when collectability is certain. Customer prepayments in excess of customer obligations remaining on account upon the expiration or termination of a contract are recognized as other operating income during the period in which the expiration or termination occurs. During the year ended December 31, 2017, the Partnership recognized $3,554 related to a contract dispute that was subsequently resolved, which is included in other operating income on our Consolidated Statements of Operations.

We generate other revenues primarily through the performance of our PropStream logistics service, which includes transportation, equipment rental, and labor services, as well as through activities performed at our in-basin terminals, including transloading sand for counterparties, and lease of storage space. Transportation services typically consist of transporting proppant from storage facilities to the wellsite and are contracted through work orders executed under established pricing agreements. The amount invoiced reflects the transportation services rendered. Equipment rental services provide customers with use of our PropStream fleet equipment for either contractual periods defined through formal agreements or for work orders under established pricing agreements. The amounts invoiced reflect either the contractual monthly minimum, or the length of time the equipment was utilized in the billing period. Labor services provide customers with supervisory, logistics, or field personnel through formal agreements or work orders executed under established pricing agreements. The amounts invoiced reflect either the contractual monthly minimum, or the amount of time our labor services were utilized in the billing period.

We typically invoice our customers as product is delivered and services are rendered, with standard collection terms of net 30 days. We recognize revenue for PropStream logistics services and other revenues as title of the product transfers and the services have been rendered and completed. At that point in time, delivery of service has occurred, evidence of a contractual arrangement exists and collectability is reasonably assured.

Deferred Revenues

We occasionally receive prepayments from customers for future deliveries of frac sand or equipment. These prepayments represent consideration that is unconditional for which we have yet to transfer title to the sand or equipment. Amounts received from customers in advance of product deliveries are recorded as contract liabilities referred to as deferred revenues and recognized as revenue upon delivery of the product.

Fair Value Measurements

The amounts reported in the balance sheet as current assets or liabilities, including cash, accounts receivable, accounts payable, accrued and other current liabilities approximate fair value due to the short-term maturities of these instruments. The Partnership's financial assets and liabilities are measured using inputs from the three levels of the fair value hierarchy, which are as follows:

• Level 1 - observable inputs such as quoted prices in active markets;

• Level 2 - inputs other than quoted prices in active markets that we can directly or indirectly observe to the extent that the markets are liquid for the relevant settlement periods; and

• Level 3 - unobservable inputs in which little or no market data exists, therefore inputs reflect the Partnership's assumptions.

F-14

HI-CRUSH PARTNERS LP

Notes to Consolidated Financial Statements

(Dollars in thousands, except unit and per unit amounts, or where otherwise noted)

The fair value of the Senior Notes approximated $329,625 as of December 31, 2018, based on the market price quoted from external sources, compared with a carrying value of $450,000. If the Senior Notes were measured at fair value in the financial statements, it would be classified as Level 2 in the fair value hierarchy.

We measure the contingent consideration liability recognized in connection with the acquisition of FB Industries at fair value on a recurring basis using unobservable inputs and it would be classified as Level 3 in the fair value hierarchy. Refer to Note 12 - Commitments and Contingencies for additional disclosure regarding contingent consideration.

Net Income per Limited Partner Unit

We have identified the sponsor’s incentive distribution rights as participating securities and compute income per unit using the two-class method under which any excess of distributions declared over net income shall be allocated to the partners based on their respective sharing of income specified in the partnership agreement. Net income per unit applicable to limited partners is computed by dividing limited partners’ interest in net income, after deducting any sponsor incentive distributions, by the weighted-average number of outstanding limited partner units. The incentive distribution rights were canceled and extinguished on October 21, 2018 in connection with the Sponsor Contribution.

As described in Note 2 - Basis of Presentation, the Partnership's historical financial information has been recast to consolidate our sponsor and general partner, Blair, Whitehall and Other Assets for all periods presented. The amounts of incremental income or losses recast to periods prior to the Sponsor Contribution, Blair Contribution and Whitehall Contribution are excluded from the calculation of net income per limited partner unit.

Income Taxes

The Partnership is a pass-through entity and is not considered a taxable entity for federal tax purposes. Therefore, there is not a provision for income taxes in the accompanying Consolidated Financial Statements. The Partnership’s net income or loss is allocated to its partners in accordance with the partnership agreement. The partners are taxed individually on their share of the Partnership’s earnings. At December 31, 2018 and 2017, the Partnership did not have any liabilities for uncertain tax positions or gross unrecognized tax benefits.

Foreign Currency Translation

The Partnership records foreign currency translation adjustments from the process of translating the functional currency of the financial statements of its foreign subsidiary into the U.S. dollar reporting currency. The Canadian dollar is the functional currency of the Partnership's foreign subsidiary as it is the primary currency within the economic environment in which the subsidiary operates. Assets and liabilities of the subsidiary's operations are translated into U.S. dollars at the rate of exchange in effect on the balance sheet date and income and expenses are translated at the average exchange rate in effect during the reporting period. Adjustments resulting from the translation of the subsidiary's financial statements are reported in other comprehensive income.

Recent Accounting Pronouncements

In February 2016, the Financial Accounting Standards Board ("FASB") issued ASU No. 2016-02, Leases (Topic 842). This update impacts all leases with durations greater than twelve months. In general, such arrangements are recognized as assets and liabilities on the balance sheet of the lessee. Under the new accounting guidance, a right-of-use asset and lease obligation is recorded for all leases, whether operating or financing, while the statement of operations reflects lease expense for operating leases and amortization/interest expense for financing leases. The balance sheet amount recorded for existing leases at the date of adoption are calculated using the applicable incremental borrowing rate at the date of adoption. The new leasing standard was effective on January 1, 2019.

The FASB has also issued the following standards which clarify ASU 2016-02 and have the same effective date as the original standard: ASU 2017-13, Revenue Recognition (Topic 605), Revenue from Contracts with Customers (Topic 606), Leases (Topic 840), and Leases (Topic 842), ASU 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842 and ASU 2018-10, Codification Improvements to Topic 842, Leases. In July 2018, the FASB also issued ASU 2018-11, Leases (Topic 842): Targeted Improvements. The amendments in this update provided entities with an optional transition method, which permitted an entity to initially apply the new leases standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. In addition, the amendments in this update also provided lessors with a practical expedient (provided certain conditions are met), by class of underlying asset, to not separate the nonlease component(s) from the associated lease component for purposes of income statement presentation.

F-15

HI-CRUSH PARTNERS LP

Notes to Consolidated Financial Statements

(Dollars in thousands, except unit and per unit amounts, or where otherwise noted)

The Partnership adopted the new leasing standard on January 1, 2019, using the modified retrospective transition adoption method, utilizing the simplified transition option available, which allows entities to continue to apply the legacy guidance in ASC 840, Leases, including its disclosure requirements, in the comparative periods presented in the year of adoption. We have elected to apply certain practical expedients, whereby we will not reassess (i) whether any expired or existing contracts are or contain leases, (ii) the lease classification for any expired or existing leases and (iii) initial direct costs for any existing leases. Upon adoption of the new leasing standard on January 1, 2019, we recognized right-of-use assets and related lease liabilities of approximately $131,000 and $121,000, respectively on the Consolidated Balance Sheet. The impact of adoption of the new leasing standard had no impact to the Consolidated Statements of Operations.

4. Acquisitions

Acquisition of Hi-Crush Proppants LLC and Hi-Crush GP LLC

On October 21, 2018, the Partnership entered into a contribution agreement with our sponsor pursuant to which the Partnership acquired all of the then outstanding membership interests in the sponsor and the non-economic general partner interest in the Partnership, in exchange for 11,000,000 newly issued common units (the "Sponsor Contribution"). In connection with the acquisition, all of the outstanding incentive distribution rights representing limited partnership interests in the Partnership were canceled and extinguished and the sponsor waived any and all rights to receive contingent consideration payments from the Partnership or our subsidiaries pursuant to certain previously entered into contribution agreements to which it was a party.

In connection with this acquisition, the Partnership incurred $3,810 of acquisition related costs during the year ended December 31, 2018, included in general and administrative expenses.

As a result of this transaction, the Partnership's historical financial information has been recast to combine the Consolidated Statements of Operations and the Consolidated Balance Sheets of the Partnership with those of our sponsor and general partner as if the combination had been in effect since inception of common control on October 28, 2010. All material transactions between the Partnership, sponsor and general partner have been eliminated. Except for the combination of the Consolidated Statements of Operations and the respective allocation of recast net income (loss), distributions paid by the sponsor to its members prior to October 21, 2018 have not been allocated on a recast basis to the Partnership’s unitholders. Such transactions are presented within the non-controlling interest column in the Consolidated Statement of Partners' Capital as the Partnership and its unitholders would not have participated in these transactions.

The following table summarizes the carrying value of our sponsor and general partner's net assets as of October 21, 2018, and the allocation of the purchase price:

Net assets of our sponsor and general partner as of October 21, 2018:
Cash	$	1,314
Accounts receivable	29
Due from Hi-Crush Partners LP	1,446
Prepaid expenses and other current assets	3,132
Property, plant and equipment	2,087
Accounts payable	(2,236		)
Accrued and other current liabilities	(2,562		)
Current portion of long-term debt	(2,259		)
Other liabilities	(86		)
Total carrying value of sponsor and general partner net assets	$	865
Allocation of purchase price
Carrying value of sponsor's non-controlling interest prior to Sponsor Contribution	$	(453,028	)
Excess purchase price over the acquired interest	453,028
Common control cost of sponsor and general partner acquisition	$	—

F-16

HI-CRUSH PARTNERS LP

Notes to Consolidated Financial Statements

(Dollars in thousands, except unit and per unit amounts, or where otherwise noted)

Acquisition of FB Industries Inc.

On August 1, 2018, the Partnership acquired FB Industries, a company engaged in the engineering, design and marketing of silo-based frac sand management systems for $45,000 in cash and 1,279,328 of newly issued common units valued at $19,190. The purchase price as of December 31, 2018 is $74,165 and is comprised of cash consideration of $54,975 which includes preliminary valuation of cash acquired and a working capital adjustment of $9,975 and the value of common units issued. The terms also include the potential for additional future consideration payments based on the achievement of established performance benchmarks through 2021. The acquisition was accounted for under the acquisition method of accounting whereby management assessed the net assets acquired and recognized amounts for the identified assets acquired and liabilities assumed. Refer to Note 12 - Commitments and Contingencies for additional disclosure regarding contingent consideration.

The purchase price of $74,165 was allocated to the net assets acquired as follows:

Net assets of FB Industries as of August 1, 2018:
Cash	$	20,015
Accounts receivable	3,788
Inventories	13,416
Goodwill and intangible assets	69,643
Prepaid expenses and other current assets	2,202
Property, plant and equipment	1,868
Accounts payable	(1,628		)
Deferred revenues	(13,004		)
Accrued and other current liabilities	(13,988		)
Contingent consideration	(8,147		)
Fair value of net assets acquired	$	74,165

The operations of FB Industries have been included in the statements prospectively from August 1, 2018. In connection with this acquisition, the Partnership incurred $639 of acquisition related costs during the year ended December 31, 2018, included in general and administrative expenses. Pro forma results of operations for FB Industries have not been presented because the FB Industries acquisition was not material to the consolidated results of operations.

Asset Acquisition of Permian Basin Sand Reserves

On March 3, 2017, the Partnership completed an acquisition of Permian Basin Sand for total consideration of $200,000 in cash and 3,438,789 newly issued common units to the sellers, valued at $62,242 based on the closing price as of March 3, 2017. Permian Basin Sand owns a 1,226-acre frac sand reserve strategically positioned in the Permian Basin, located within 75 miles of significant Delaware and Midland Basin activity.

The acquisition of Permian Basin Sand was accounted for as an asset acquisition as the acquired assets did not constitute a business. The total purchase consideration of $263,072 is reflected as property, plant and equipment on the Consolidated Balance Sheet. The following table summarizes the total purchase consideration:

Cash paid to sellers	$	200,000
Issuance of common units to sellers	62,242
Transactions costs associated with the acquisition	830
Cost of Permian Basin Sand acquisition	$	263,072

Acquisition of Hi-Crush Whitehall LLC and Other Assets

On February 23, 2017, the Partnership entered into a contribution agreement with our sponsor to acquire all of the outstanding membership interests in Whitehall and Other Assets, for $140,000 in cash and up to $65,000 of contingent consideration over a two-year period. The Partnership completed this acquisition on March 15, 2017. In connection with this acquisition, the Partnership incurred $588 of acquisition related costs during the year ended December 31, 2017, included in general and administrative expenses.

F-17

HI-CRUSH PARTNERS LP

Notes to Consolidated Financial Statements

(Dollars in thousands, except unit and per unit amounts, or where otherwise noted)

The contingent consideration was based on the Partnership's adjusted earnings before interest, taxes, depreciation and amortization ("Adjusted EBITDA") exceeding certain thresholds for each of the fiscal years ending December 31, 2017 and 2018. As of March 15, 2017, the estimated fair value of the contingent consideration liability based on available information at the time of the acquisition was $14,000. During the first quarter of 2018, the Partnership paid $20,000 of contingent consideration with respect to the 2017 measurement period. In October 2018, the Partnership completed the acquisition of its sponsor and general partner and the remaining contingent consideration arrangements were terminated.

As a result of this transaction, the Partnership's historical financial information has been recast to combine the Consolidated Statements of Operations and the Consolidated Balance Sheets of the Partnership with those of Whitehall and Other Assets as if the combination had been in effect since inception of common control on August 16, 2012. All material transactions between the Partnership, Whitehall and Other Assets have been eliminated.

The following table summarizes the carrying value of the Whitehall and Other Assets net assets as of March 15, 2017, and the allocation of the purchase price:

Net assets of Hi-Crush Whitehall LLC and Other Assets as of March 15, 2017:
Cash	$	198
Inventories	4,941
Prepaid expenses and other current assets	3
Property, plant and equipment	124,811
Accounts payable	(938		)
Accrued and other current liabilities	(386		)
Due to Hi-Crush Partners LP	(2,615		)
Asset retirement obligation	(1,716		)
Total carrying value of Whitehall and Other Assets net assets	$	124,298
Allocation of purchase price
Carrying value of sponsor's non-controlling interest prior to Whitehall Contribution	$	119,108
Excess purchase price over the acquired interest (a)	34,892
Cost of Whitehall and Other Assets acquisition	$	154,000

(a) The deemed distribution attributable to the purchase price was allocated to the common unitholders and excludes the $14,000 estimated fair value of contingent consideration.

Acquisition of Hi-Crush Blair LLC

On August 9, 2016, the Partnership entered into a contribution agreement with our sponsor to acquire all of the outstanding membership interests in Blair, the entity that owned our sponsor’s Blair facility, for $75,000 in cash, 7,053,292 of newly issued common units in the Partnership, and payment of up to $10,000 of contingent consideration. The Partnership completed the acquisition of the Blair facility on August 31, 2016. In connection with this acquisition, the Partnership incurred $850 of acquisition related costs during the year ended December 31, 2016, included in general and administrative expenses.

The contingent consideration was based on the Partnership's Adjusted EBITDA exceeding certain thresholds for each of the fiscal years ending December 31, 2017 and 2018. As of August 31, 2016, the estimated fair value of the contingent consideration liability based on available information at the time of the acquisition was $5,000. During the first quarter of 2018, the Partnership paid $5,000 of contingent consideration with respect to the 2017 measurement period. In October 2018, the Partnership completed the acquisition of its sponsor and general partner and the remaining contingent consideration arrangements were terminated.

As a result of this transaction, the Partnership's historical financial information has been recast to combine the Consolidated Statements of Operations and the Consolidated Balance Sheets of the Partnership with those of Blair as if the combination had been in effect since inception of common control on July 31, 2014. All material transactions between the Partnership and Blair have been eliminated.

F-18

HI-CRUSH PARTNERS LP

Notes to Consolidated Financial Statements

(Dollars in thousands, except unit and per unit amounts, or where otherwise noted)

The following table summarizes the carrying value of Blair's assets as of August 31, 2016, and the allocation of the cash consideration payable:

Net assets of Hi-Crush Blair LLC as of August 31, 2016:
Cash	$	75
Inventories	6,310
Prepaid expenses and other current assets	360
Due from Hi-Crush Partners LP	406
Property, plant and equipment	125,565
Other assets	700
Accounts payable	(5,653		)
Accrued and other current liabilities	(2,269		)
Due to sponsor	(311		)
Due to Hi-Crush Partners LP	(1,240		)
Asset retirement obligation	(380		)
Total carrying value of Blair's net assets	$	123,563
Allocation of purchase price
Carrying value of sponsor's non-controlling interest prior to Blair Contribution	$	125,571
Excess carrying value over the purchase price of the acquired interest (a)	(45,571		)
Cost of Blair acquisition	$	80,000

(a) The deemed contribution attributable to the purchase price was allocated to the common unitholders and excludes the $5,000 estimated fair value of contingent consideration.

Recast Financial Results

The following tables present, on a supplemental basis, our recast revenues, net income (loss), net income (loss) attributable to Hi-Crush Partners LP and net income (loss) per limited partner unit giving effect to the Sponsor Contribution, Blair Contribution and Whitehall Contribution, as reconciled to the revenues, net income (loss), net income (loss) attributable to Hi-Crush Partners LP and net income (loss) per limited partner unit of the Partnership.

	Year Ended December 31, 2018
	Partnership Historical		Sponsor and General Partner through October 21, 2018			Eliminations		Partnership Recast (Supplemental)
Revenues	$	842,840	$	—		$	—	$	842,840
Net income (loss)	$	140,790	$	(3,195	)	$	—	$	137,595
Net income (loss) attributable to Hi-Crush Partners LP	$	140,790	$	(3,195	)	$	—	$	137,595
Net income per limited partner unit - basic	$	1.46						$	1.42

F-19

HI-CRUSH PARTNERS LP

Notes to Consolidated Financial Statements

(Dollars in thousands, except unit and per unit amounts, or where otherwise noted)

	Year Ended December 31, 2017
	Partnership Historical		Sponsor and General Partner			Whitehall and Other Assets through March 15, 2017			Eliminations			Partnership Recast (Supplemental)
Revenues	$	602,623	$	—		$	—		$	—		$	602,623
Net income (loss)	$	83,979	$	(6,372	)	$	(1,366	)	$	(79	)	$	76,162
Net income (loss) attributable to Hi-Crush Partners LP	$	84,005	$	(6,372	)	$	(1,392	)	$	(79	)	$	76,162
Net income per limited partner unit - basic	$	0.97										$	0.88

	Year Ended December 31, 2016
	Partnership Historical			Sponsor and General Partner			Blair through August 31, 2016		Whitehall and Other Assets			Eliminations			Partnership Recast (Supplemental)
Revenues	$	204,430		$	—		$	13,761	$	8,275		$	(22,036	)	$	204,430
Net income (loss)	$	(81,412	)	$	(8,506	)	$	716	$	(3,778	)	$	(45	)	$	(93,025	)
Net income (loss) attributable to Hi-Crush Partners LP	$	(81,313	)	$	(8,506	)	$	716	$	(3,877	)	$	(45	)	$	(93,025	)
Net loss per limited partner unit - basic	$	(1.64	)												$	(1.88	)

5. Inventories

Inventories consisted of the following:

	December 31,
	2018		2017
Raw material	$	512	$	498
Work-in-process	29,180		18,739
Finished goods	24,872		22,892
Spare parts	2,525		2,143
Inventories	$	57,089	$	44,272

F-20

HI-CRUSH PARTNERS LP

Notes to Consolidated Financial Statements

(Dollars in thousands, except unit and per unit amounts, or where otherwise noted)

6. Property, Plant and Equipment

Property, plant and equipment consisted of the following:

	December 31,
	2018			2017
Buildings	$	32,751		$	22,084
Mining property and mine development	390,296			381,653
Plant and equipment	472,892			383,183
Rail and rail equipment	55,913			55,783
Transload facilities and equipment	118,982			116,688
Last mile equipment	66,083			14,276
Construction-in-progress	21,796			14,507
Property, plant and equipment	1,158,713			988,174
Less: Accumulated depreciation and depletion	(127,525		)	(88,164		)
Property, plant and equipment, net	$	1,031,188		$	900,010

Depreciation and depletion expense was $38,775, $29,872 and $17,616 for the years ended December 31, 2018, 2017 and 2016, respectively.

The Partnership recognized a (gain) loss on the disposal of fixed assets of $369, $92 and $(357) during the years ended December 31, 2018, 2017 and 2016, respectively, which is included in general and administrative expenses on our Consolidated Statements of Operations.

7. Goodwill and Intangible Assets

Changes in goodwill and intangible assets consisted of the following:

	Goodwill			Intangible Assets
Balance at December 31, 2016	$	—		$	10,097
Amortization expense	—			(1,681		)
Balance at December 31, 2017	—			8,416
Additions from FB Industries acquisition	22,876			46,767
Impact of foreign currency translation	(995		)	(2,115		)
Amortization expense	—			(3,374		)
Balance at December 31, 2018	$	21,881		$	49,694

Goodwill

As of December 31, 2018, the Partnership had goodwill of $21,881 based on the allocation of the purchase price of its acquisition of FB Industries.

F-21

HI-CRUSH PARTNERS LP

Notes to Consolidated Financial Statements

(Dollars in thousands, except unit and per unit amounts, or where otherwise noted)

Intangible Assets

Intangible assets arising from the acquisition of FB Industries in 2018 and the acquisition of D&I Silica, LLC ("D&I") in 2013 consisted of the following:

		December 31,
	Useful life	2018			2017
Patents	15 Years	$	29,620		$	—
Customer contracts and relationships	1-10 Years	28,724			18,132
Supplier agreements	1-20 Years	21,997			21,997
Other intangible assets	1-3 Years	6,161			1,749
Intangible assets		86,502			41,878
Less: Accumulated amortization and impairments		(36,808		)	(33,462		)
Intangible assets, net		$	49,694		$	8,416

Amortization expense was $3,374 and $1,681 for the years ended December 31, 2018 and 2017, respectively. The weighted average remaining life of intangible assets was 14.25 years as of December 31, 2018.

As of December 31, 2018, future amortization is as follows:

Fiscal Year	Amortization
2019	$	5,781
2020	5,781
2021	5,781
2022	5,781
2023	3,271
Thereafter	23,299
	$	49,694

8. Equity Method Investments

The following table provides our net investments and the proportionate share of our equity method investments operating results:

	Investment				Earnings (loss) from Equity Method Investments
	December 31,				Year Ended December 31,
	2018		2017		2018			2017		2016
Proppant Express Investments, LLC	$	30,870	$	17,475	$	5,300		$	75	$	—
Proppant Logistics LLC	6,484		—		(116		)	—		—
Total	$	37,354	$	17,475	$	5,184		$	75	$	—

Investment in Proppant Express Investments, LLC

On September 8, 2016, the Partnership entered into an agreement to become a member of Proppant Express Investments, LLC ("PropX"), which was established to develop critical last mile logistics equipment for the proppant industry. PropX is responsible for manufacturing containers and conveyor systems that allow for transportation of frac sand from in-basin terminals to the wellsite. During the years ended December 31, 2018, 2017 and 2016, the Partnership made capital contributions of $8,095, $7,168 and $10,232 to PropX.

Investment in Proppant Logistics LLC

On October 31, 2018, the Partnership invested $6,600 into Proppant Logistics LLC, a logistics company which provides frac sand services in North America.

F-22

HI-CRUSH PARTNERS LP

Notes to Consolidated Financial Statements

(Dollars in thousands, except unit and per unit amounts, or where otherwise noted)

9. Accrued and Other Current Liabilities

Accrued and other current liabilities consisted of the following:

	December 31,
	2018		2017
Accrued royalty payments	$	6,429	$	8,763
Accrued logistics costs	10,422		5,878
Accrued compensation and benefits	12,144		9,368
Accrued taxes payable	10,917		5,140
Accrued interest payable	18,464		505
Other current liabilities	2,961		3,796
Accrued and other current liabilities	$	61,337	$	33,450

10. Long-Term Debt

Long-term debt consisted of the following:

	December 31,
	2018			2017
Senior Notes due 2026	$	450,000		$	—
ABL Credit Facility	—			—
Term Loan Credit Facility	—			200,000
Other notes payable	4,852			4,237
Less: Unamortized original issue discount	—			(1,992		)
Less: Unamortized debt issuance costs	(9,375		)	(3,643		)
Total debt	445,477			198,602
Less: current portion of long-term debt	(2,194		)	(4,140		)
Long-term debt	$	443,283		$	194,462

Senior Notes due 2026

On August 1, 2018, the Partnership completed the private placement of $450,000 aggregate principal amount of its 9.50% senior unsecured notes due 2026 (the "Senior Notes"). The Senior Notes were issued under and are governed by an indenture, dated as of August 1, 2018 (the "Indenture"), by and among the Partnership, the guarantors named therein (the "Guarantors"), and U.S. Bank National Association, as trustee. The Senior Notes are fully and unconditionally guaranteed (the "Guarantees"), jointly and severally, on a senior unsecured basis by the Guarantors. The Indenture contains customary terms, events of default and covenants relating to, among other things, the incurrence of debt, the payment of dividends or similar restricted payments, undertaking transactions with the Partnership's unrestricted affiliates, and limitations on asset sales. The Senior Notes bear interest at an annual rate of 9.50% and are payable semi-annually.

At any time prior to August 1, 2021, the Partnership may redeem up to 35% of the aggregate principal amount of the Senior Notes at a redemption price equal to 109.50% of the principal amount, plus accrued and unpaid interest, if any, to the redemption date, with an amount of cash not greater than the net proceeds from certain equity offerings. At any time prior to August 1, 2021, the Partnership may redeem the Senior Notes, in whole or in part, at a redemption price equal to 100% of the principal amount of the Senior Notes plus a "make-whole" premium plus accrued and unpaid interest, if any, to the redemption date. The Partnership may also redeem all or a part of the Senior Notes at any time on or after August 1, 2021, at the redemption prices set forth in the Indenture, plus accrued and unpaid interest, if any, to the redemption date. If the Partnership experiences a change of control, the Partnership may be required to offer to purchase the Senior Notes at a purchase price equal to 101% of the principal amount, plus accrued and unpaid interest, if any, to the purchase date.

F-23

HI-CRUSH PARTNERS LP

Notes to Consolidated Financial Statements

(Dollars in thousands, except unit and per unit amounts, or where otherwise noted)

The Senior Notes and the Guarantees rank equally in right of payment with all of the Partnership’s and the Guarantors’ existing and future senior indebtedness, effectively junior to all of the Partnership’s existing and future secured indebtedness, including borrowings the ABL Credit Facility, to the extent of the value of the assets securing such indebtedness, structurally junior to any indebtedness of the Partnership’s subsidiaries that do not guarantee the Senior Notes (including trade payables), and senior to all of the Partnership’s and the Guarantors’ future subordinated indebtedness.

As of December 31, 2018, we had $440,625 of indebtedness ($450,000, net of $9,375 of debt issuance costs) under our Senior Notes.

ABL Credit Facility

On August 1, 2018, the Partnership, entered into a senior secured revolving credit facility (the "ABL Credit Facility"), which matures on August 1, 2023, among the Partnership, as borrower, the lenders party thereto from time to time, and JP Morgan Chase Bank, N.A., as administrative agent and an issuing lender, and each other issuing lender party thereto. The ABL Credit Facility permits aggregate borrowings of up to $200,000, including a $50,000 sublimit for letters of credit, with the ability to increase the amount of permitted aggregate borrowings up to $300,000 subject to certain conditions.

As of December 31, 2018, we had $58,073 of available borrowing capacity ($79,493, net of $21,420 letter of credit commitments) and no indebtedness under our ABL Credit Facility.

The obligations of the Partnership under the ABL Credit Facility are secured by substantially all assets of the Partnership (other than real estate and other customary exclusions). In addition, the Partnership’s subsidiaries guarantee the Partnership’s obligations under the ABL Credit Facility and grant to the administrative agent security interests in substantially all of their respective assets (other than real estate and other customary exclusions).

Borrowings under the ABL Credit Facility bear interest at a rate equal to, at the Partnership’s option, either (1) a base rate plus an applicable margin ranging between 0.75% per annum and 1.50% per annum, based upon the Partnership’s leverage ratio, or (2) a LIBOR rate plus an applicable margin ranging between 1.75% per annum and 2.50% per annum, based upon the Partnership’s leverage ratio.

The ABL Credit Facility contains customary representations and warranties and customary affirmative and negative covenants, including limits or restrictions on the Partnership’s ability to incur liens, incur indebtedness, make certain restricted payments, merge or consolidate and dispose of assets. In certain limited circumstances, the ABL Credit Facility requires compliance with a fixed charge coverage ratio. In addition, it contains customary events of default that entitle the lenders to cause any or all of the Partnership’s indebtedness under the ABL Credit Facility to become immediately due and payable. The events of default (some of which are subject to applicable grace or cure periods) include, among other things, non-payment defaults, covenant defaults, cross-defaults to other material indebtedness, bankruptcy and insolvency defaults, and material judgment defaults. As of December 31, 2018, the Partnership was in compliance with all covenants in the ABL Credit Facility.

Revolving Credit Agreement

On December 22, 2017, the Partnership entered into a second amended and restated credit agreement (the "Revolving Credit Agreement"). On August 1, 2018, upon execution of the ABL Credit Facility described above, the Revolving Lenders commitments under the Revolving Credit Agreement were terminated and the outstanding liabilities of the Partnership with respect to its obligations under the Revolving Credit Agreement were released and discharged.

Term Loan Credit Facility

On December 22, 2017, the Partnership entered into an amended and restated credit agreement providing for a senior secured term loan credit facility (the "Term Loan Credit Facility") that permits aggregate borrowings of up to $200,000, which was fully drawn on December 22, 2017. On August 1, 2018, in connection with the closing of the Senior Notes, the Partnership repaid its outstanding debt, including accrued interest, under the Term Loan Credit Facility. The payment was made prior to the maturity date and no early payment penalties were incurred by the Partnership.

Other Notes Payable

In 2014, the Partnership entered into a purchase and sales agreement to acquire land and underlying frac sand deposits. During the year ended December 31, 2018, the Partnership issued a three-year promissory note to obtain additional mineral rights on the previously acquired land in the amount of $3,676 due in August 2021 with an interest rate of 2.42%. During the year ended December 31, 2016, the Partnership paid cash consideration of $2,500, and issued a three-year promissory note in the amount of $3,676 due in December 2019 with an interest rate of 0.74%. The promissory notes accrue interest at rates equal to the applicable short-term federal rates. All principal and accrued interest is due and payable at the end of the respective three-year promissory note terms. However, the promissory notes are prepaid on a quarterly basis during the three-year terms if sand is extracted, delivered, sold and paid for from the properties.

F-24

HI-CRUSH PARTNERS LP

Notes to Consolidated Financial Statements

(Dollars in thousands, except unit and per unit amounts, or where otherwise noted)

During the years ended December 31, 2018 and 2017, the Partnership made prepayments of $3,378 and $3,651, respectively, based on the accumulated volume of sand extracted, delivered, sold and paid for. In January 2019, the Partnership made a prepayment of $694 based on the volume of sand extracted, delivered, sold and paid for through the fourth quarter of 2018. As of December 31, 2018, the Partnership had repaid in full the promissory note due in December 2019 and had $3,352 outstanding on the remaining promissory note.

Other notes payable also consisted of short-term obligations, arising from insurance premium financing programs bearing interest ranging from approximately 4.99% to 6.29%, with outstanding balances of $1,500 as of December 31, 2018.

Maturities

As of December 31, 2018, future minimum debt repayments, excluding debt issuance costs, are as follows:

Fiscal Year	Amount
2019	$	2,194
2020	—
2021	2,658
2022	—
2023	—
Thereafter	450,000
	$	454,852

Debt Refinancing and Extinguishment

On December 22, 2017, the Partnership replaced our amended and restated credit agreement and our senior secured term loan credit facility by entering into the Revolving Credit Agreement and the Term Loan Credit Facility. In connection with the refinancing, the Partnership recognized a $4,332 loss on extinguishment of debt, which represents the write-off of all remaining unamortized debt issuance costs and unamortized original issuance discount.

On August 1, 2018, the Partnership completed the private placement of $450,000 aggregate principal amount of its 9.50% Senior Notes and entered into the ABL Credit Facility. Upon closing on the Senior Notes and ABL Credit Facility, the Partnership terminated the Revolving Credit Agreement and Term Loan Credit Facility. In connection with the terminations, the Partnership recognized a $6,233 loss on extinguishment of debt, which represents the write-off of all remaining unamortized debt issuance costs and unamortized original issuance discount.

11. Asset Retirement Obligations

Although the ultimate amount of reclamation and closure costs to be incurred is uncertain, the Partnership maintained a post-closure reclamation and site restoration obligation as follows:

Balance at December 31, 2015	$	8,711
Additions to liabilities	373
Accretion expense	430
Balance at December 31, 2016	9,514
Additions to liabilities	207
Accretion expense	458
Balance at December 31, 2017	10,179
Accretion expense	498
Balance at December 31, 2018	$	10,677

F-25

HI-CRUSH PARTNERS LP

Notes to Consolidated Financial Statements

(Dollars in thousands, except unit and per unit amounts, or where otherwise noted)

12. Commitments and Contingencies

Customer Contracts

The Partnership enters into sales contracts with customers. These contracts establish minimum annual sand volumes that the Partnership is required to make available to such customers under initial terms ranging from one to seven years. Through December 31, 2018, no payments for non-delivery of minimum annual sand volumes have been made by the Partnership to customers under these contracts.

Royalty Agreements

The Partnership has entered into royalty agreements under which it is committed to pay royalties on sand sold from its production facilities for which the Partnership has received payment by the customer. Royalty expense is recorded as the sand is sold and is included in costs of goods sold. Royalty expense was $15,478, $19,091 and $6,725 for the years ended December 31, 2018, 2017 and 2016, respectively.

Certain acreage is subject to a minimum annual royalty payment. If not paid within 30 days after the annual period, the original landowner has the right to purchase the property for one dollar, subject to certain terms. If we have not made the minimum required royalty payments, we may satisfy our obligation by making a lump-sum cash make-whole payment. Accordingly, we believe there is no material risk that we will be required to sell back the subject property pursuant to this agreement.

Property Value Guarantees

The Partnership entered into mining agreements and land use agreements with the Wisconsin municipalities of Bridge Creek, Lincoln, Springfield and Preston that contain property value guarantees ("PVG") for certain property owners in proximity to each mine. The respective PVGs establish a process whereby we guaranty fair market value to the owners of residential property specifically identified within the body of the PVG document. According to the terms of the PVGs, the property owner must notify us in the event they wish to sell the subject residence and additional acreage in certain instances. Upon such notice, the PVGs establish a process by which an appraisal is conducted and the subject property is appraised to establish fair market value and is listed with a real estate broker. In the event the property is sold within 180 days of listing, we agree to pay the owner any shortfall between the sales price and the established fair market value. In the event the property is not sold within the 180 days time frame, we are obligated to purchase the property for fair market value.

As of December 31, 2018, we have not accrued a liability related to the PVGs because it is not possible to estimate how many of the owners will elect to avail themselves of the provisions of the PVGs and it cannot be determined if shortfalls will exist in the event of a sale nor can the value of the subject property be ascertained until appraised. As of December 31, 2018, the Partnership has paid $3,085 under these guarantees since inception.

Lease Obligations

The Partnership has long-term leases for railcars, equipment and certain of its terminals. Railcar rental expense was $31,393, $27,410 and $28,597 for the years ended December 31, 2018, 2017 and 2016, respectively.

The Partnership entered into long-term operating leases with PropX for use of equipment manufactured and owned by PropX.  Lease expense associated with PropX equipment was $5,306, $1,577 and $124 for the years ended December 31, 2018, 2017 and 2016, respectively.

We have entered into service agreements with certain transload service providers which requires us to purchase minimum amounts of services over specific periods of time at specific locations. Our failure to purchase the minimum level of services would require us to pay shortfall fees.

F-26

HI-CRUSH PARTNERS LP

Notes to Consolidated Financial Statements

(Dollars in thousands, except unit and per unit amounts, or where otherwise noted)

As of December 31, 2018, future minimum operating lease payments and minimum purchase commitments are as follows:

Fiscal Year	Operating Leases		Minimum Purchase Commitments
2019	$	36,019	$	7,346
2020	36,282		3,745
2021	29,272		2,424
2022	20,890		2,344
2023	10,280		2,182
Thereafter	31,066		677
	$	163,809	$	18,718

Contingent Consideration

In connection with the acquisition of FB Industries, the agreement contained certain contingent consideration arrangements from the date of closing to December 31, 2021, dependent upon leases or sales of certain silo systems or conveyors to be paid quarterly. The acquisition date estimated fair value of the contingent consideration of $8,147 is recorded as other liabilities on the Consolidated Balance Sheet as of December 31, 2018. Changes in fair value of the contingent consideration prior to finalizing the purchase price allocation are accounted for as a working capital adjustment. Subsequent changes in fair value of the contingent consideration after the measurement period are recognized in earnings in the period identified.

The estimated fair value assumes only leases are entered into during this period. A 10% increase or decrease in the assumed quantity of lease would result in an increase of $10,324 or a decrease of $6,299, respectively, in the fair value of the contingent consideration. Conversely, a 50% shift in the assumed quantity of leases to sales of silo systems and conveyors would reduce the contingent consideration to $3,152.

Litigation

From time to time the Partnership may be subject to various claims and legal proceedings which arise in the normal course of business. Management is not aware of any legal matters that are likely to have a material adverse effect on the Partnership’s financial position, results of operations or cash flows.

13. Equity

Equity Issuances

The Partnership issued 1,279,328 of common units as additional consideration for the FB Industries acquisition on August 1, 2018.

During the year ended December 31, 2017, the Partnership completed a public offering for a total of 23,575,000 common units representing limited partnership interests in the Partnership for aggregate net proceeds of approximately $412,577. The net proceeds from this offering were used to fund the cash portion of the Whitehall Contribution, the cash portion of the Permian Basin Sand asset acquisition and for general partnership purposes. In addition, the Partnership issued 3,438,789 common units as additional consideration for the Permian Basin Sand asset acquisition on March 3, 2017.

During the year ended December 31, 2016, the Partnership completed three public offerings for a total of 19,550,000 common units representing limited partnership interests in the Partnership for aggregate net proceeds of approximately $189,037. The net proceeds from these offerings were used to pay off the outstanding balance under the Partnership's Revolving Credit Agreement, to fund the Blair Contribution and for general partnership purposes.

Unit Buyback Program

On October 17, 2017, the Partnership announced that the board of directors of our general partner approved a unit buyback program of up to $100,000. The repurchase program does not obligate the Partnership to repurchase any specific dollar amount or number of units and may be suspended, modified or discontinued by the board of directors at any time, in its sole discretion and without notice.

F-27

HI-CRUSH PARTNERS LP

Notes to Consolidated Financial Statements

(Dollars in thousands, except unit and per unit amounts, or where otherwise noted)

The following table presents information with respect to repurchases of common units made by the Partnership during the periods presented, which were retired upon repurchase:

	Year Ended December 31,
	2018		2017
Number of units purchased	753,090		2,030,163
Average price paid per unit including commission	$	12.52	$	9.85
Total cost	$	9,426	$	20,000

As of December 31, 2018, the Partnership has repurchased a total of 2,783,253 common units for a total cost of $29,426, with $70,574 remaining under its approved unit buyback program.

Equity Distribution Agreement

On January 4, 2017, the Partnership entered into an equity distribution program with certain financial institutions (each, a "Manager") under which we may sell, from time to time, through or to the Managers, common units representing limited partner interests in the Partnership up to an aggregate gross sales price of $50,000. The Partnership has not issued any common units under this equity distribution program through the date of this filing.

Incentive Distribution Rights

Incentive distribution rights represent the right to receive increasing percentages (ranging from 15.0% to 50.0%) of quarterly distributions from operating surplus after minimum quarterly distribution and target distribution levels exceed $0.54625 per unit, per quarter. The incentive distribution rights were held by our sponsor and were canceled and extinguished on October 21, 2018 in connection with the Sponsor Contribution.

Allocations of Net Income

Our partnership agreement contains provisions for the allocation of net income and loss to the unitholders and our general partner. For purposes of maintaining partner capital accounts, the partnership agreement specifies that items of income and loss shall be allocated among the partners in accordance with their respective percentage ownership interest. Normal allocations according to percentage interests were made after giving effect, if any, to priority income allocations in an amount equal to incentive cash distributions allocated 100% to our sponsor for the periods applicable prior to the Sponsor Contribution.

During the year ended December 31, 2018, $7,664 was allocated to the holder of our incentive distribution rights prior to the Sponsor Contribution. During the years ended December 31, 2017 and 2016, no income was allocated to the holder of our incentive distribution rights.

Distributions

Our partnership agreement sets forth the calculation to be used to determine the amount of cash distributions that our limited partner unitholders will receive and the holder of our incentive distribution rights received prior to the Sponsor Contribution.

On October 26, 2015, we announced the decision of the board of directors of our general partner to temporarily suspend the distribution payment to common unitholders in an effort to conserve cash. On October 16, 2017, the board of directors reinstated quarterly distributions.

Our most recent distributions have been as follows:

Declaration Date	Amount Declared Per Unit		Record Date	Payment Date	Payment to Limited Partner Units		Payment to the Holder of Incentive Distribution Rights
October 16, 2017	$	0.1500	October 31, 2017	November 14, 2017	$	13,656	$	—
January 17, 2018	$	0.2000	February 1, 2018	February 13, 2018	$	17,809	$	—
April 18, 2018	$	0.2250	May 1, 2018	May 15, 2018	$	19,888	$	—
July 20, 2018	$	0.7500	August 3, 2018	August 14, 2018	$	67,253	$	7,664
October 21, 2018	$	0.2250	November 1, 2018	November 14, 2018	$	22,695	$	—

F-28

HI-CRUSH PARTNERS LP

Notes to Consolidated Financial Statements

(Dollars in thousands, except unit and per unit amounts, or where otherwise noted)

On January 7, 2019, we announced the decision of the board of directors of our general partner to suspend the quarterly distribution to common unitholders.

Net Income per Limited Partner Unit

The following table outlines our basic and diluted, weighted average limited partner units outstanding during the relevant periods:

	Year Ended December 31,
	2018	2017	2016
Basic common units outstanding	91,248,042	86,518,249	49,567,268
Potentially dilutive common units	2,390,138	1,382,733	—
Diluted common units outstanding	93,638,180	87,900,982	49,567,268

For purposes of calculating the Partnership’s earnings per unit under the two-class method, common units are treated as participating preferred units. Prior to the Sponsor Contribution, the incentive distribution rights were treated as participating securities.

Diluted earnings per unit excludes any dilutive awards granted (see Note 14 - Unit-Based Compensation) if their effect is anti-dilutive. Diluted earnings per unit for the years ended December 31, 2018 and 2017, includes the dilutive effect of 2,390,138 and 1,382,733, respectively, of awards granted and outstanding at the assumed number of units which would have vested if the performance period had ended at the end of the respective periods. During the year ended December 31, 2016, the Partnership incurred a net loss and, and as a result, all 579,781 of potentially dilutive awards granted and outstanding were excluded from the diluted earnings per unit calculation.

Distributions made in future periods based on the current period calculation of cash available for distribution are allocated to each class of equity that will receive such distributions.

Each period, the Partnership determines the amount of cash available for distributions in accordance with the partnership agreement. The amount to be distributed to limited partner unitholders and incentive distribution rights holder is subject to the distribution waterfall in the partnership agreement for the periods applicable prior to the Sponsor Contribution. Net earnings or loss for the period are allocated to each class of partnership interest based on the distributions to be made.

As described in Note 2 - Basis of Presentation, the Partnership's historical financial information has been recast to combine our sponsor and general partner, Blair, Whitehall and Other Assets for all periods presented. The amounts of incremental income or losses recast to periods prior to the Sponsor Contribution, Blair Contribution and Whitehall Contribution are excluded from the calculation of net income per limited partner unit.

The following tables provide a reconciliation of net income (loss) and the assumed allocation of net income (loss) under the two-class method for purposes of computing net income (loss) per limited partner unit for the years ended December 31, 2018, 2017 and 2016 (in thousands, except per unit amounts):

	Year Ended December 31, 2018
	General Partner and IDRs		Limited Partner Units		Total
Declared distribution	$	7,664	$	109,836	$	117,500
Assumed allocation of earnings in excess of distributions	—		20,095		20,095
Add back recast losses attributable to our sponsor and general partner through October 21, 2018	—		3,195		3,195
Assumed allocation of net income	$	7,664	$	133,126	$	140,790
Earnings per limited partner unit - basic			$	1.46
Earnings per limited partner unit - diluted			$	1.42

F-29

HI-CRUSH PARTNERS LP

Notes to Consolidated Financial Statements

(Dollars in thousands, except unit and per unit amounts, or where otherwise noted)

	Year Ended December 31, 2017
	General Partner and IDRs		Limited Partner Units		Total
Declared distribution	$	—	$	31,457	$	31,457
Assumed allocation of earnings in excess of distributions	—		44,705		44,705
Add back recast losses attributable to our sponsor and general partner	—		6,372		6,372
Add back recast losses attributable to Whitehall and Other Assets through March 15, 2017	—		1,471		1,471
Assumed allocation of net income	$	—	$	84,005	$	84,005
Earnings per limited partner unit - basic			$	0.97
Earnings per limited partner unit - diluted			$	0.96

	Year Ended December 31, 2016
	General Partner and IDRs		Limited Partner Units			Total
Declared distribution	$	—	$	—		$	—
Assumed allocation of distributions in excess of loss	—		(93,025		)	(93,025		)
Add back recast losses attributable to our sponsor and general partner	—		8,506			8,506
Add back recast income attributable to Blair through August 31, 2016	—		(279		)	(279		)
Add back recast losses attributable to Whitehall and Other Assets	—		3,485			3,485
Assumed allocation of net loss	$	—	$	(81,313	)	$	(81,313	)
Loss per limited partner unit - basic			$	(1.64	)
Loss per limited partner unit - diluted			$	(1.64	)

Recast Equity Transactions

During the years ended December 31, 2018 and 2017, our sponsor paid cash distributions of $39,516 and $69,215, respectively, to its members. During the year ended December 31, 2016, our sponsor did not pay any cash distributions to its members. Such transactions are reflected within the non-controlling interest section of the accompanying Consolidated Statement of Partners' Capital.

During the year ended December 31, 2017, our sponsor distributed its 20,693,643 common units in the Partnership to its members.

On October 21, 2018, in connection with the closing on the Sponsor Contribution, $453,028 of non-controlling interest was converted to limited partner capital.

F-30

HI-CRUSH PARTNERS LP

Notes to Consolidated Financial Statements

(Dollars in thousands, except unit and per unit amounts, or where otherwise noted)

14. Unit-Based Compensation

Long-Term Incentive Plan

On August 21, 2012, Hi-Crush GP LLC adopted the Hi-Crush Partners LP Long-Term Incentive Plan, which was superseded on September 21, 2016 by the First Amended and Restated Long-Term Incentive Plan (the "Plan") for employees, consultants and directors of Hi-Crush GP LLC and those of its affiliates, including our sponsor, who perform services for the Partnership. The Plan consists of restricted units, unit options, phantom units, unit payments, unit appreciation rights, other equity-based awards, distribution equivalent rights and performance awards. The Plan limited the number of common units that may be issued pursuant to awards under the Plan to 4,064,035 units. After giving effect to the Plan, to the extent that an award is forfeited, canceled, exercised, settled in cash, or otherwise terminates or expires without the actual delivery of common units pursuant to such awards, the common units subject to the award will again be available for new awards granted under the Plan; provided, however, that any common units withheld to cover a tax withholding obligation will not again be available for new awards under the Plan. The Plan is administered by Hi-Crush GP LLC’s board of directors or a committee thereof.

The cost of services received in exchange for an award of equity instruments is measured based on the grant-date fair value of the award and that cost is generally recognized over the vesting period of the award.

Performance Phantom Units - Equity Settled

The Partnership has awarded Performance Phantom Units ("PPUs") pursuant to the Plan to certain employees. The number of PPUs that will vest will range from 0% to 200% of the number of initially granted PPUs and is dependent on the Partnership's total unitholder return over a three-year performance period compared to the total unitholder return of a designated peer group. Each PPU represents the right to receive, upon vesting, one common unit representing limited partner interests in the Partnership. The PPUs are also entitled to forfeitable distribution equivalent rights ("DERs"), which accumulate during the performance period and are paid in cash on the date of settlement. The fair value of each PPU is estimated using a fair value approach and is amortized into compensation expense, reduced for an estimate of expected forfeitures, over the period of service corresponding with the vesting period. Expected volatility is based on the historical market performance of our peer group. The following table presents information relative to our PPUs.

	Units		Grant Date Weighted-Average Fair Value per Unit
Outstanding at December 31, 2017	346,141		$	14.56
Vested	(60,528	)	$	32.45
Granted	468,500		$	3.40
Forfeited	(6,193	)	$	33.93
Outstanding at December 31, 2018	747,920		$	5.93

As of December 31, 2018, total compensation expense not yet recognized related to unvested PPUs was $2,181, with a weighted average remaining service period of 2.1 years. The weighted average grant date fair value per unit for PPUs granted during the years ended December 31, 2018, 2017 and 2016 was $3.40, $6.85 and $15.94, respectively. The total fair value of units vested during the year ended December 31, 2018 was $1,964. During the years ended December 31, 2017 and 2016, no units vested.

Time-Based Phantom Units - Equity Settled

The Partnership has awarded Time-Based Phantom Units ("TPUs") pursuant to the Plan to certain employees which automatically vest if the employee remains employed at the end of the vesting period. The vesting period is a cliff or graded vesting, generally ranging over a three-year period. Each TPU represents the right to receive, upon vesting, one common unit representing limited partner interests in the Partnership. The TPUs are also entitled to forfeitable DERs, which accumulate during the vesting period and are paid in cash on the date of settlement. The fair value of each TPU is calculated based on the grant-date unit price and is amortized into compensation expense, reduced for an estimate of expected forfeitures, over the period of service corresponding with the vesting period. The following table presents information relative to our TPUs.

F-31

HI-CRUSH PARTNERS LP

Notes to Consolidated Financial Statements

(Dollars in thousands, except unit and per unit amounts, or where otherwise noted)

	Units		Grant Date Weighted-Average Fair Value per Unit
Outstanding at December 31, 2017	1,036,592		$	10.97
Vested	(248,724	)	$	14.68
Granted	967,357		$	6.91
Forfeited	(113,007	)	$	10.21
Outstanding at December 31, 2018	1,642,218		$	8.07

As of December 31, 2018, total compensation expense not yet recognized related to unvested TPUs was $8,944, with a weighted average remaining service period of 2.2 years. The weighted average grant date fair value per unit for TPUs granted during the years ended December 31, 2018, 2017 and 2016 was $6.91, $8.94 and $12.96, respectively. The total fair value of units vested during the years ended December 31, 2018, 2017 and 2016 was $3,651, $714 and $62, respectively.

Director Unit Grants

The Partnership issued 36,109, 29,148 and 103,377 common units to certain of its directors during the years ended December 31, 2018, 2017 and 2016, respectively. In January 2019, the Partnership issued 62,184 common units to certain of its directors.

Unit Purchase Programs

The Partnership has unit purchase programs ("UPP") offered under the Plan. The UPPs provide participating employees and members of our general partner's board of directors the opportunity to purchase common units representing limited partner interests of the Partnership at a discount. Non-director employees contribute through payroll deductions of the employee's eligible compensation during the applicable offering period. Directors contribute through cash contributions. If the closing price of the Partnership's common units on the purchase date is greater than or equal to the discount applied to the closing market price of our common units on a participant's applicable election date (the "Election Price"), then the participant will receive a number of common units equal to the amount of accumulated payroll deductions or cash contributions, as applicable, (the "Contribution"), divided by the Election Price, capped at a specified number of common units. If the purchase date price is less than the Election Price, then the participant’s Contribution will be returned to the participant. On the date of election, the Partnership calculates the fair value of the discount, which is recognized as unit compensation expense on a straight-line basis during the period from election date through the date of purchase. 

The offering period under the Partnership's UPP adopted in 2015 (the "2015 UPP") ended on February 28, 2017 with a 10% discount of the fair value of our common units on the applicable election date. The participants under the 2015 UPP purchased 300,090 common units at an average price of $5.49 on February 28, 2017.

On September 14, 2017, the board of directors of our general partner approved the termination of the Partnership's UPP that was adopted in March of 2017 (the "2017 UPP") and approved the adoption of the Second 2017 Unit Purchase Program (the "Second 2017 UPP"). On September 14, 2017, the offering period under the Second 2017 UPP commenced, with a 15% discount of the fair value of our common units on the applicable election date and a purchase date of November 15, 2018. The offering period under the Second 2017 UPP ended on November 15, 2018, at which time the purchase date price was less than the Election Price. As a result, all contributions were returned to the participants and no common units were purchased under the Second 2017 UPP.

Compensation Expense

The following table presents total unit-based compensation expense:

	Year Ended December 31,
	2018		2017		2016
Performance Phantom Units	$	1,371	$	1,549	$	634
Time-Based Phantom Units	5,261		3,149		1,359
Director and other unit grants	474		499		474
Unit Purchase Programs	333		517		153
Total compensation expense	$	7,439	$	5,714	$	2,620

F-32

HI-CRUSH PARTNERS LP

Notes to Consolidated Financial Statements

(Dollars in thousands, except unit and per unit amounts, or where otherwise noted)

15. Revenues

As described in Note 3, on January 1, 2018, we adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606), using the full retrospective method. In accordance with Topic 606, the Partnership recognizes revenue at the point in time control of the promised goods or services is transferred to our customers, in an amount that reflects the consideration we expect to be entitled to in exchange for those goods or services. A performance obligation is a promise in a contract to transfer a distinct good or service to the customer, and is the unit of account in Topic 606. A contract's transaction price is allocated to each distinct performance obligation and recognized as revenue when, or as, the performance obligation is satisfied.

The majority of our contracts are frac sand contracts that have a single performance obligation as the promise to transfer individual goods or services is not separately identifiable from other promises in the contracts and, therefore, not distinct. For the portion of our contracts that contain multiple performance obligations, such as work orders containing a combination of product, transportation, equipment rentals, and labor services, we allocate the transaction price to each performance obligation identified in the contract based on relative stand-alone selling prices, or estimates of such prices, and recognize the related revenue as control of each individual product or service is transferred to the customer, in satisfaction of the corresponding performance obligations.

Disaggregation of Revenues

The following table presents our revenues disaggregated by contractual relationships:

	Year Ended December 31,
	2018		2017		2016
Sales to contract customers	$	607,898	$	438,547	$	169,696
Spot sales	88,705		159,808		33,013
Frac sand sales revenues	696,603		598,355		202,709
Other revenues	146,237		4,268		1,721
Total revenues	$	842,840	$	602,623	$	204,430

Practical Expedients and Exemptions

We have elected to use the practical expedients allowed under ASC 606-10-50-14, pursuant to which we have excluded disclosures of transaction prices allocated to remaining performance obligations and when we expect to recognize such revenue. We have various long-term contracts with minimum purchase and supply requirements with terms expiring between 2020 and 2024. The remaining performance obligations are primarily comprised of unfulfilled product, transportation service, and labor service orders, some of which hold a remaining duration of less than one year. Our transaction price for volumes and services under these contracts is based on timing of customer orders, points of sale, mix of products sold, impact of market conditions and potential contract negotiations, which have not yet been determined and therefore the price is variable in nature. The long term portion of deferred revenue represents customer prepayments for which related current performance obligations do not yet exist, but are expected to arise, before the expiration of the term.

Deferred Revenues

As of December 31, 2018, the Partnership has recorded a total liability of $29,785 for prepayments of future deliveries of frac sand. Some prepayments are refundable in the event that the Partnership is unable to meet the minimum requirements under certain contracts. We expect to recognize these revenues over the next 1.7 years.

The following table reflect the changes in our contract liabilities, which we classify as deferred revenues:

Balance at December 31, 2017	$	11,783
Collection of prepayments	33,841
Revenues recognized	(25,696		)
Customer payments acquired in purchase of FB Industries	9,911
Impact of foreign currency translation	(54		)
Balance at December 31, 2018	$	29,785

F-33

HI-CRUSH PARTNERS LP

Notes to Consolidated Financial Statements

(Dollars in thousands, except unit and per unit amounts, or where otherwise noted)

16. Related Party Transactions

On September 8, 2016, the Partnership entered into an agreement to become a member of PropX, which is accounted for as an equity method investment. During the years ended December 31, 2018 and 2017, the Partnership purchased $4,646 and $5,033, respectively, of equipment from PropX, which is reflected in property, plant and equipment. As of December 31, 2018 and 2017, the Partnership had accounts payable of $1,070 and $1,273, respectively, to PropX, which is reflected in accounts payable on our Consolidated Balance Sheet. In addition to equipment purchases, during the years ended December 31, 2018, 2017 and 2016, we incurred $5,306, $1,577 and $124, respectively, of lease expense for the use of PropX equipment, which is reflected in cost of goods sold.

During the years ended December 31, 2018, 2017 and 2016, the Partnership engaged in multiple construction projects and purchased equipment, machinery and component parts from various vendors that were represented by Alston Environmental Company, Inc. or Alston Equipment Company ("Alston Companies"), which regularly represent vendors in such transactions. The vendors in question paid a commission to the Alston Companies in an amount that is unknown to the Partnership. The sister of Mr. Alston, who was a director of our general partner, has an ownership interest in the Alston Companies. The Partnership has not paid any sum directly to the Alston Companies and Mr. Alston has represented to the Partnership that he received no compensation from the Alston Companies related to these transactions.

17. Impairments and Other Operating Expenses

During the year ended December 31, 2016, the Partnership recognized a $33,745 impairment loss of goodwill, which arose from the acquisition of D&I in 2013 and was therefore allocated to the D&I reporting unit. During the three months ended March 31, 2016, volumes sold through the D&I reporting unit declined below previously forecasted levels and pricing deteriorated further. Our customers faced uncertainty related to activity levels and reduced their active frac crews, resulting in declines in well completion activity and industry demand for frac sand. Therefore, as of March 31, 2016, we determined that the state of market conditions and activity levels indicated that an impairment of goodwill may exist. As a result, we assessed qualitative factors and determined that we could not conclude it was more likely than not that the fair value of goodwill exceeded its carrying value. In turn, we prepared a quantitative analysis of the fair value of the goodwill as of March 31, 2016, based on the weighted average valuation across several income and market based valuation approaches. The underlying results of the valuation were driven by our actual results during the three months ended March 31, 2016 and the pricing, costs structures and market conditions existing as of March 31, 2016, which were below our forecasts at the time of the previous goodwill assessments. Other key estimates, assumptions and inputs used in the valuation included long-term growth rates, discounts rates, terminal values, valuation multiples and relative valuations when comparing the reporting unit to similar businesses or asset bases. Upon completion of the Step 1 and Step 2 valuation exercises, it was determined that an impairment loss of all goodwill was incurred, which was equal to the difference between the carrying value and estimated fair value of goodwill.

We recognized impairments and other expenses as outlined in the following table:

	Year Ended December 31,
	2018		2017		2016
Impairment of Goodwill	$	—	$	—	$	33,745
Severance, retention and relocation	1,549		40		280
Contract settlement	1,000		—		—
Exploration expenses	1		143		—
Abandonment of construction projects	—		460		—
Expiration of exclusivity agreements	—		222		—
Other	215		—		—
Impairments and other expenses	$	2,765	$	865	$	34,025

18. Segment Reporting

The Partnership manages, operates and owns assets utilized to supply frac sand to its customers. It conducts operations through its one operating segment titled "Frac Sand Sales". This reporting segment of the Partnership is evaluated regularly by the chief operating decision maker in deciding how to allocate resources and in assessing performance.

F-34

19. Concentration of Credit Risk

The Partnership is a producer of sand mainly used by the oil and natural gas industry for fracturing wells. The Partnership’s business is, therefore, dependent upon economic activity within this market. The following table provides our significant customers that had sales greater than 10% for the years ended December 31, 2018, 2017 and 2016:

	Year Ended December 31,
	2018		2017		2016
Customer A	22	%	*		*
Customer B	16	%	26	%	28	%
Customer C	*		11	%	17	%
Customer D	*		*		14	%
Customer E	*		*		19	%

*  Less than 10%

Throughout 2018, the Partnership has maintained cash balances in excess of federally insured amounts on deposit with financial institutions.

20. Quarterly Financial Data (Unaudited)

As discussed in Note 2 - Basis of Presentation, the Sponsor Contribution and Whitehall Contribution were accounted for as transactions between entities under common control. Therefore, the Partnership's historical financial information has been recast to include our sponsor and general partner and Whitehall and Other Assets for all periods presented.

2018	First Quarter			Second Quarter		Third Quarter (a)		Fourth Quarter			Total
Revenues	$	218,113		$	248,520	$	213,972	$	162,235		$	842,840
Gross profit	68,331			83,507		56,148		18,596			226,582
Income from operations	55,738			69,534		39,759		(1,040		)	163,991
Net income (loss)	53,431			66,956		27,138		(9,930		)	137,595
Earnings (loss) per limited partner unit:
Basic	$	0.60		$	0.68	$	0.30	$	(0.08	)	$	1.46
2017
Revenues	$	83,364		$	135,220	$	167,583	$	216,456		$	602,623
Gross profit	6,453			27,742		38,823		61,808			134,826
Income (loss) from operations	(5,795		)	17,978		32,059		49,148			93,390
Net income (loss)	(10,962		)	15,824		29,372		41,928			76,162
Earnings (loss) per limited partner unit:
Basic	$	(0.07	)	$	0.18	$	0.33	$	0.48		$	0.97

(a) The third quarter of 2017 includes $3,554 of other operating income related to a contract dispute that was subsequently resolved.

F-35

HI-CRUSH PARTNERS LP

Notes to Consolidated Financial Statements

(Dollars in thousands, except unit and per unit amounts, or where otherwise noted)

21. Subsequent Events

Corporate Conversion

The board of directors of out general partner unanimously approved a Plan of Conversion pursuant to which, subject to unitholder approval, the Partnership would effect its proposed conversion from a Delaware limited partnership to a Delaware corporation (the "Conversion"). The Partnership filed a preliminary proxy statement with the U.S. Securities and Exchange Commission on February 5, 2019. The proxy statement relates to a special meeting of unitholders that is expected to be held on April 11, 2019, and at which unitholders will be asked to consider and vote upon proposals relating to the Conversion. As a result of the Conversion, the Partnership will convert from an entity treated as a partnership for U.S. federal income tax purposes to an entity treated as a corporation for U.S. federal income tax purposes.

F-36

HI-CRUSH PARTNERS LP

Schedule II - Valuation and Qualifying Accounts

(In thousands)

	Balance at Beginning of Period		Charged to Costs and Expenses		Deductions			Balance at End of Period
Allowance for doubtful accounts
Year Ended December 31, 2018	$	1,060	$	—	$	—		$	1,060
Year Ended December 31, 2017	$	1,549	$	—	$	(489	)	$	1,060
Year Ended December 31, 2016	$	663	$	8,236	$	(7,350	)	$	1,549

F-37