10-K

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, 2017

or

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

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

Three Riverway, Suite 1350

Houston, Texas 77056

(Former address)

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

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 ¨
(Do not check if a 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, 2017, 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 $887,328,114 based on the closing price of $10.85 per common unit on that date.

As of February 15, 2018, there were 89,130,197 common units outstanding.

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	39
Item 2. Properties	39
Item 3. Legal Proceedings	43
Item 4. Mine Safety Disclosures	43
PART II
Item 5. Market for Registrant’s Common Units, Related Unitholder Matters and Issuer Purchases of Unit Securities	44
Item 6. Selected Financial Data	47
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	50
Item 7A. Quantitative and Qualitative Disclosures About Market Risk	65
Item 8. Financial Statements and Supplementary Data	65
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	66
Item 9A. Controls and Procedures	66
Item 9B. Other Information	67
PART III
Item 10. Directors, Executive Officers and Corporate Governance	68
Item 11. Executive Compensation	74
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	91
Item 13. Certain Relationships and Related Transactions, and Director Independence	92
Item 14. Principal Accounting Fees and Services	95
PART IV
Item 15. Exhibits, Financial Statement Schedules	97
Item 16. Form 10-K Summary	99

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," "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 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 price and availability of transportation;

• 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;

• industrial and transportation related accidents;

• fires, explosions or other accidents;

• difficulty collecting receivables;

• inability of our customers to take delivery;

• difficulties in obtaining and renewing environmental permits;

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

• changes in laws and regulations (or the interpretation 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;

• inability to acquire or maintain necessary permits, licenses or other approvals, including mining or water 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; and

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• 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 "Hi-Crush Partners LP," "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 "Hi-Crush Proppants LLC" and "our sponsor" refer to Hi-Crush Proppants LLC.

Overview

Hi-Crush Partners LP (together with its subsidiaries, the "Partnership") is a premier provider of proppant and logistics solutions to the North American energy industry. Our portfolio of production facilities is capable of producing 13.4 million tons per year of high-quality monocrystalline sand, a specialized mineral used as a proppant during the well completion process, necessary to facilitate the recovery of hydrocarbons from oil and natural gas wells. Our Wisconsin production facilities' direct access to major U.S. railroads and our strategically located owned and operated in-basin terminals as well as our Texas production facility positions us within close proximity to significant activity in all major oil and gas basins. Our integrated distribution system, including our PropStream^TM logistics service, delivers proppant the "last mile" into the blender.

Over the past decade, exploration and production companies have focused on exploiting the vast hydrocarbon reserves contained in North America’s unconventional oil and natural gas reservoirs through advanced techniques, such as horizontal drilling and hydraulic fracturing. In recent years, this focus has resulted in exploration and production companies drilling longer horizontal wells, completing more hydraulic fracturing stages per well and utilizing more proppant per stage in an attempt to efficiently maximize the volume of hydrocarbon recovery per well. As a result, North American proppant demand, and particularly raw frac sand, increased rapidly over the same period.

Beginning in August 2014 and continuing through the second quarter of 2016, oil and natural gas prices declined dramatically in response to global supply concerns. Oil and natural gas prices persisted at levels well below those experienced during the middle of 2014. In response, U.S. exploration and production companies sharply reduced their drilling and completion activities in an effort to control costs. As a result, the number of rigs drilling for oil and gas fell dramatically in that same period from the high levels achieved during third quarter of 2014. Well completion activity throughout 2016 was significantly below levels experienced in 2014 and 2015. The combination of these and other factors reduced proppant demand and pricing during 2016 considerably from those realized during 2014. However, proppant demand did not decline as precipitously as rig count or well completion activity, due to the continuing trend of longer laterals and increasing use of proppant per lateral foot in well completions, all of which have positive impacts on frac sand demand.

Beginning in the fourth quarter of 2016 and continuing throughout 2017, North American rig count and well completion activity increased meaningfully over levels experienced in the middle of 2016. Demand for frac sand increased at a higher rate than well completion activity due to continued increases in proppant intensity per well. During the same time frame, frac sand supply increased at a slower rate, even with the resumption of operations at several previously idled mines. This dynamic led to a dramatic increase in frac sand pricing during the first quarter of 2017, which has continued to increase throughout 2017 and into 2018.

Given the energy industry's outlook for 2018 activity levels, we expect well completion activity to continue to improve over the next several quarters, which, coupled with higher usage of frac sand per well, should result in an increased positive influence on demand for raw frac sand. Supply of frac sand is expected to increase in 2018 as development of new Permian Basin production facilities are completed and ramp up operations. However, we believe this new supply will lag further increases in demand, presenting continued positive impact on supply and demand dynamics, and therefore potentially preserving a constructive environment for pricing stability or improvement.

We utilize the significant oil and natural gas industry experience of our management team to take advantage of what we believe are favorable, long-term market dynamics as we execute our growth strategy, which includes the expansion of our integrated distribution system and PropStream logistics service, as well as potential development of new terminal facilities and other logistics related assets.

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" or "Hi-Crush GP"), and a 100% limited partner interest to our sponsor, its organizational limited partner.

Acquisition of Hi-Crush Augusta LLC

In January 2013 and April 2014, the Partnership entered into agreements with our sponsor which ultimately resulted in the acquisition of 98.0% of the common equity interests in Hi-Crush Augusta LLC ("Augusta"), the entity that owns a 1,187-acre facility with integrated rail infrastructure, located in Eau Claire County, Wisconsin (the "Augusta facility").

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Acquisition of D & I Silica, LLC

In June 2013, the Partnership acquired an independent frac sand supplier, D & I Silica, LLC ("D&I"), transforming the Partnership into an integrated Northern White frac sand producer, transporter, marketer and distributor. Founded in 2006, D&I was the largest independent frac sand supplier to the oil and gas industry drilling in the Marcellus and Utica shale plays.

Acquisition of Hi-Crush Blair LLC

On August 9, 2016, the Partnership entered into a contribution agreement with the sponsor to acquire all of the outstanding membership interests in Hi-Crush Blair LLC ("Blair"), the entity that owned our sponsor's 1,285-acre facility with integrated rail infrastructure, located near Blair, Wisconsin (the "Blair facility"), for $75.0 million in cash, 7,053,292 of newly issued common units in the Partnership, and payment of up to $10.0 million of contingent consideration over a two-year period (the "Blair Contribution"). The Partnership completed the acquisition of the Blair facility on August 31, 2016.

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 Hi-Crush Whitehall LLC ("Whitehall"), the entity that owned our sponsor’s 1,447-acre facility with integrated rail infrastructure, located near Independence, Wisconsin and Whitehall, Wisconsin (the "Whitehall facility"), the remaining 2.0% equity interest in Augusta, and all of the outstanding membership interests in PDQ Properties LLC (together, the "Other Assets"), for $140.0 million in cash and up to $65.0 million of contingent consideration over a two-year period (the "Whitehall Contribution"). The Partnership completed this acquisition on March 15, 2017.

Asset Acquisition of Permian Basin Sand Reserves

On March 3, 2017, the Partnership completed an acquisition of Permian Basin Sand Company, LLC ("Permian Basin Sand") for total consideration of $200.0 million in cash and 3,438,789 newly issued common units to the sellers, valued at $62.2 million based on the closing price as of March 3, 2017. 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, within 75 miles of significant Delaware and Midland Basin activity.

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 of 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).

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, 2017, contained 74.1 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 40 years as of December 31, 2017.

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

The Augusta facility, as of December 31, 2017, contained 38.6 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 13 years as of December 31, 2017. As a result of market conditions, the Augusta facility was temporarily idled in October 2015 until production resumed at reduced capacity levels in September 2016. We resumed production at rates near full capacity in April 2017.

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.

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Blair Facility

The Blair facility, as of December 31, 2017, contained 114.9 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 40 years as of December 31, 2017.

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 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.

Whitehall Facility

The Whitehall facility, as of December 31, 2017, contained 78.2 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 27 years as of December 31, 2017. As a result of market conditions, the Whitehall facility was temporarily idled during the second quarter of 2016 and resumed production in March 2017.

All of the product from the Whitehall facility is shipped by rail from approximately 34,000 feet of track that connects the facility to a Canadian National 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.

Kermit Facility

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. The Kermit facility, as of December 31, 2017, contained 103.6 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 facility has an implied reserve life of 35 years as of December 31, 2017.

All of the product from our Kermit facility is delivered by truck to the wellsite from five on-site silos with 15,000 tons of storage capacity.

Terminal Facilities

As of December 31, 2017, we own or operate 12 terminal locations throughout Colorado, Pennsylvania, Ohio, New York and Texas, of which two are temporarily idled and seven are capable of accommodating unit trains. Our terminals include approximately 109,000 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, 2017, we leased or owned 4,253 railcars used to transport sand from origin to destination and managed a fleet of approximately 2,404 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, which involves loading proppant at in-basin terminals into PropX containers before being transported by truck to the wellsite. 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. 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. PropStream also provides flexible and scalable storage at the wellsite compared to silo solutions and more precise delivery of proppant into the blender hopper.

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At the wellsite, the proprietary conveyor system, PropBeast^®, significantly reduces noise and dust emissions due to its enclosed environment. 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. Our PropStream integrated logistics service is designed meet or exceed the new U.S. Occupational Safety and Health Act ("OSHA") respirable crystalline silica standards set to become effective in 2018 with respect to hydraulic fracturing, as well as the engineering control obligations set to become effective in 2021 for hydraulic fracturing.

As of December 31, 2017, we owned 22 PropBeast conveyors and leased 1,249 containers from PropX. 

Competitive Strengths

We believe that we are well positioned to successfully execute our strategy and achieve our primary business objectives to provide capital appreciation and increase our return to unitholders through cash distributions per unit and unit repurchases over time because of the following competitive strengths:

• Competitive operating cost structure. Our plant operations have been strategically designed to provide low per-unit production costs. 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. At our Kermit facility, our production costs benefit from a reserve base that is easily accessible with limited to no overburden. 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. All of our Wisconsin facilities are capable of accommodating unit trains, and enable efficient loading of frac sand and minimize rail car turnaround times at the facilities. 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. Our Kermit facility, located in the heart of the Permian Basin, is capable of loading produced frac sand directly into the truck and is logistically advantaged with proximity to significant frac sand demand and wellsite locations. In addition, many of our terminals are capable of receiving and handling unit trains, further reducing the cost of delivered sand for our customers. 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.

• Strategically located terminal facilities. We deliver our frac sand through an extensive logistics network of owned and operated rail-based terminals strategically located throughout Colorado, Pennsylvania, Ohio, New York and Texas 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 service our customers’ short-notice needs across basins, at a lower price, and provide our customers with solutions for the logistical challenges presented by the large volume of frac sand typically required for each well completion. Our network of terminals located in the Marcellus and Utica shale plays is situated within 50 miles of approximately 80% of all wells permitted in these shale plays in 2017, providing our customers with the opportunity for reduced trucking and logistics costs to deliver frac sand to the wellsite. Our three terminals in the Permian Basin, combined with the industry’s first operational in-basin mine at Kermit, provide a platform for efficient delivery of frac sand within 50 miles of approximately 80% of all wells permitted in the Permian Basin in 2017.

• "Last mile" service. Our PropStream integrated logistics service expands the reach and delivery of our production facilities and our owned and operated terminal network directly to our customers’ usage points, while leveraging our logistics infrastructure advantage and utilizing our strategically located terminal facilities. The development and expansion of "last mile" capabilities in our portfolio of services is aligned with our goals of delivering frac sand from the mine to the wellsite more efficiently. These efforts also expand our customer base by selling directly to the end users, and positioning our company deeper into the sand supply chain with delivery of sand to the blender hopper. PropStream reduces costs and environmental impact by simplifying the proppant delivery process through a fully flexible service. The PropStream service’s greater operating efficiency reduces non-productive time and demurrage costs at the wellsite, improves truck cycle times and enhances frac sand inventory management. The PropBeast conveyor system provides significant environmental benefits, including a reduction in silica dust by more than 90% as compared to the use of pneumatic trailers and other techniques, while also significantly reducing wellsite noise. PropStream benefits from superior accuracy and reliability through highly precise sand delivery and greater than 99% uptime efficiency, as well as gravity-fed loading and unloading, faster speeds load times and more consistent fills. The container size, and its mobility, enhances operational flexibility. We believe our customized PropStream service offering meets the specific needs of our customers today and is designed to do so as completion designs evolve.

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• Long-term customer relationships. We generate a substantial portion of our revenues from the sale of frac sand to customers with whom we have long-term relationships, supported by contracts. The contracts specify annual minimum volume requirements for customers and have an average remaining contractual term of 2.6 years. In 2015 and 2016, as a result of the existing market dynamics, we provided our 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 based on market pricing. Our contracts for sand sourced from our Kermit facility are generally fixed price for the life of the contract. We believe our long-term relationships with our customers provide us with a stable base of frac sand demand and cash flows.

• Experienced and incentivized management team. Our management team has extensive experience investing and operating in the oil and natural gas industry, long-term relationships with participants in the oilfield services and exploration and production 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, frac sand supply chain management, and bulk solids material handling. Our management team is focused on optimizing our current business and expanding our operations through disciplined execution of our operational strategy of Mine. Move. Manage. Our management team and members of our general partner's board of directors are well-aligned with the interests of common unitholders through their combined 10% direct ownership interest in our limited partnership units and 39% interest in our sponsor, which owns 100% of the incentive distribution rights, whose value are directly impacted by prudent growth in profitability, cash flows and the business overall.

Business Strategies

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

• 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 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. Over the long-term, we believe increases in frac sand supply will be constrained by challenges associated with reliably matching the reserves and natural mesh size distribution with the logistics and customer needs, in the quantities required. Additionally, we expect ongoing difficulty with successfully obtaining the necessary local, state and federal permits required for operating proppant facilities and related infrastructure.

• 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. 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.

• Focusing on long-term relationships with key customers. A key component of our business model has been our contracting strategy, which seeks to secure a high percentage of our volumes under long-term contracts with major pressure pumping service providers and oil and gas exploration and production companies. Our mix of fixed price and market price in our contracts for sand sourced from our Wisconsin facilities and our fixed price contracts for sand sourced from our Kermit facility provide us with a stable base of frac sand demand and cash flows, 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.

• 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 last mile solution for delivery of sand, 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.

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• Pursuing accretive acquisitions. In June 2013, we acquired 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 Colorado, Pennsylvania, Ohio, New York and Texas. In separate transactions in 2013, 2014, 2016 and 2017, we acquired all of the equity interests in the Augusta, Blair and Whitehall facilities from our sponsor. In March 2017, we acquired a 1,226-acre frac sand reserve, located near Kermit, Texas from Permian Basin Sand. 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.

• 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 15, 2018, our senior secured term loan credit facility (the "Term Loan Credit Facility") that permits aggregate borrowings of $200.0 million was fully drawn with a $200.0 million balance outstanding and we had $104.3 million of undrawn borrowing capacity ($125.0 million, net of $20.7 million letter of credit commitments) and had no indebtedness under our senior secured revolving credit agreement (the "Revolving Credit Agreement"). The Revolving Credit Agreement is available to fund working capital and general corporate purposes, including the making of certain restricted payments permitted therein. Borrowings under our Revolving Credit Agreement are secured by substantially all of our assets. 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 2017 and 2016, we completed four public offerings for 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.

Our Industry

The oil and natural gas proppant industry is comprised of businesses involved in the mining or manufacturing of the propping agents used in the drilling and 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.

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 gas producers generally require that frac sand used in their drilling and completion processes meet API specifications.

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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, is sometimes preferred due to its proximity to shale basins, particularly the Permian Basin and Eagle Ford shale plays, and, therefore, lower cost due to reduced logistics costs. In-Basin frac sand began to be developed and produced in 2017 and is used in the Permian Basin due to its proximity and logistics advantage. 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. Pressured (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 30 mesh screen has 30 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 30/50 mesh size proppant must consist of granules that will pass through a 30 mesh screen but not through a 50 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 growth for frac sand and other proppants is primarily driven by advancements in oil and natural gas drilling and well completion technology and techniques, such as horizontal drilling and hydraulic fracturing, as well as overall industry activity growth. These advancements have made the extraction of oil and natural gas increasingly cost-effective in formations that historically would have been unprofitable to develop, resulting in a greater number of wells being drilled. Demand for proppant declined in 2015 and throughout most of 2016 with reduced well completion activity; however, we believe that demand for proppant will continue to grow, as it did throughout 2017, over the long-term, primarily driven by the increase in the average amount of proppant consumed per horizontal rig and 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 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.

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Supply Trends

As demand for raw frac sand increased dramatically through 2014, the supply of raw frac sand failed to keep pace, resulting in a supply-demand disparity. As a result, a number of existing and new competitors announced supply expansions and greenfield projects. However, there are several key 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 multiple counties 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.

As a result of the decline in oil and natural gas exploration and production activity that took place in 2015 and throughout most of 2016, many announced expansions or greenfield projects were significantly delayed or canceled. In addition, several existing facilities were temporarily or permanently idled, often due to high cost of production.

Recommencement of production at facilities previously idled often requires significant maintenance costs, use of working capital to build sufficient wet sand inventory for processing and hiring of employees if previously laid off. As a result, we do not believe some idled facilities will re-enter the market until frac sand pricing has reached a sustained and higher level to incentivize the investment.

In 2017, several new and existing suppliers announced planned capacity additions of frac sand supply, particularly in the Permian Basin. We expect frac sand supply to lag growth in demand over the coming months and quarters. While planned capacity may exceed the expectations for frac sand demand, the collectively available industry capacity is constrained due to 1) availability of the grades of sand that are currently in demand, 2) general operating conditions and normal downtime and 3) logistics constraints. The industry is expected to add capacity over the next 12 to 18 months, particularly in the Permian Basin; however, we do not expect such supply to be available in the volume grades or timeframe needed to efficiently meet the increasing demand. The advent of "In-Basin" sand supply available closer to the wellsite in the Permian Basin may cause a shift in supply over time from Northern White sand to In-Basin sand supply. However, we believe this shift will be 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 grades 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.

Pricing

Given the expectation for increased oil and natural gas exploration and production activity in North America, coupled with the increased demand per well, and the limitations to increase sand supply noted above, frac sand pricing has risen throughout 2017 and into the first quarter of 2018, and we believe is likely to be more favorable in 2018.

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.

Customers and Contracts

Our current customer base includes major pressure pumping service providers and oil and gas exploration and production companies. For the year ended December 31, 2017, sales to each of Halliburton Company ("Halliburton") and Liberty Oilfield Services ("Liberty") accounted for greater than 10% of our total revenues.

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We sell the majority of the frac sand we produce to customers with whom we have long-term contracts. For the year ended December 31, 2017, we generated 73% 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 2018 and future years. As of January 1, 2018, our long-term contracts have an average remaining contractual term of 2.6 years with remaining terms ranging from 12 to 84 months.

The terms of our customer contracts, including sand quality requirements, quantity parameters, permitted sources of supply, effects of future regulatory changes, force majeure and termination and assignment provisions, vary by customer. Our contracts contain penalties for non-performance by our customers. If one of our customers fails to meet its minimum obligations to us, make-whole payments, combined with the decrease in our variable costs (such as production costs, royalty payments and transportation costs), can mitigate the adverse impact on our cash flow from such failures. In addition, we have the ability to sell these sand volumes to third parties.

Our long-term customer contracts also contain penalties for our non-performance. If we are unable to deliver contracted volumes or otherwise arrange for delivery from a third party, we may be required to pay make-whole payments. We believe our production facilities, substantial reserves and our on-site processing and logistics capabilities reduce our risk of non-performance. We believe our levels of inventory are sufficient to prevent us from paying make-whole payments as a result of plant shutdowns due to repairs to our facilities necessitated by reasonably foreseeable mechanical interruptions.

In addition to sales under our long-term contracts, we sell raw frac sand under short-term pricing and other agreements. The terms of our short-term pricing agreements, including sand quality requirements, quantity parameters, permitted sources of supply, effects of future regulatory changes, force majeure and termination and assignment provisions, vary by customer.

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, 2017 and 2015, the Partnership purchased 142,019 and 96,151 tons, respectively, from third parties. During the year ended December 31, 2016, the Partnership did not purchase any sand from third parties. 

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 Augusta, Blair, Whitehall and Kermit facilities the excavation process involves clearing vegetation and trees, if any, 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 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.

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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 plant operates 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 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 34,000 feet, respectively, of track that connects our facility to a Canadian National Railroad 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 facility is delivered by truck to the wellsite from five on-site silos with 15,000 tons of storage capacity.

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 at 10 tons per minute 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 integrated logistics service involves loading proppant at in-basin terminals into PropX 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.  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. PropStream also provides flexible and scalable storage at the wellsite compared to silo solutions and more precise delivery of proppant into the blender hopper.

At the wellsite, the PropBeast conveyor system significantly reduces noise and dust emissions due to its enclosed environment.  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. Our PropStream integrated logistics service is designed to meet or exceed the new OSHA respirable crystalline silica standards set to become effective in 2018 with respect to hydraulic fracturing, as well as the engineering control obligations set to become effective in 2021 for hydraulic fracturing.

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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 include:

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

• Unimin Corporation ("Unimin")

• Fairmount Santrol Holdings, Inc. ("Fairmount") (NASDAQ: FMSA)

• Badger Mining Corporation

• Emerge Energy Services LP (NYSE: EMES)

• Smart Sand, Inc. (NASDAQ: SND)

On December 12, 2017, Unimin and Fairmount announced a planned merger. In addition, there are several Permian Basin production facilities anticipated to become operational in 2018. As these Permian Basin production facilities become operational, our main competitors could change.

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 Our Sponsor

Overview and History

Hi-Crush Proppants LLC, our sponsor, was formed in 2010 in Houston, Texas by members of our management team and our general partner's board of directors, who currently have a 39% membership interest in our sponsor. Our sponsor’s lead investor is Avista Capital Partners ("Avista"), a leading private equity firm. Founded in 2005 by senior investment professionals who worked together at DLJ Merchant Banking Partners, then one of the world’s largest and most successful private equity franchises, Avista makes controlling or influential minority investments in connection with various transaction structures.

Our Sponsor’s Assets

Our sponsor initially developed and constructed the Wyeville, Augusta, Whitehall and Blair facilities prior to their contribution or sale to the Partnership.

Our sponsor continually evaluates acquisitions and may elect to acquire, construct or dispose of assets in the future, including through sales of assets to us. As the owner of our general partner and incentive distribution rights, our sponsor is well aligned and highly motivated to promote and support the successful execution of our business strategies, including utilizing our partnership as a growth vehicle for its sand mining operations. Although we may make additional acquisitions directly from our sponsor in the future, our sponsor is under no obligation to accept any offer we make, and may, following good faith negotiations with us, sell any assets to third parties that may compete with us. Our sponsor may also elect to develop, retain and operate properties in competition with us.

Although we believe our relationship with our sponsor is a significant positive attribute, it may also be a source of conflict. For example, our sponsor is not restricted in its ability to compete with us. Our sponsor may develop processing facilities and logistics capabilities in the future, which may compete with us.

Our Management and Employees

We are managed and operated by the board of directors and executive officers of our general partner, Hi-Crush GP, a wholly owned subsidiary of our sponsor. As a result of owning our general partner, our sponsor 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 New York Stock Exchange ("NYSE"). Our unitholders are not entitled to elect our general partner or its 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.

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We have entered into a services agreement with a wholly owned subsidiary of our sponsor which governs our relationship with our sponsor and its subsidiaries regarding the provisions of certain administrative services to us. In addition, under our partnership agreement, we reimburse our general partner and its affiliates, including our sponsor, for all expenses they incur and payments they make on our behalf, to the extent such expenses are not contemplated by the services agreement. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us.

Hi-Crush Partners LP does not have any employees. All of the employees who conduct our business pursuant to the services agreement are employed by Hi-Crush Proppants LLC or its wholly owned subsidiaries. As of December 31, 2017, Hi-Crush Proppants LLC and its wholly owned subsidiaries had 601 employees. In addition, we contract our excavation and trucking operations to third parties and accordingly have no employees involved in those operations.

Environmental and Occupational Safety and Health Regulation

Mining and Workplace Safety

Federal Regulation

The U.S. Mine Safety and Health Administration ("MSHA") is the primary regulatory agency with jurisdiction over the commercial silica industry. Accordingly, MSHA regulates quarries, surface mines, underground mines, and the industrial mineral processing facilities associated with quarries and mines. 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.

We also are subject to the requirements of the OSHA and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA Hazard Communication Standard requires that information be maintained about hazardous materials used or produced in 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 the OSHA Hazard Communication Standard.

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 both health and safety issues, extensive training is provided to employees. We have safety meetings at our plants with salaried and hourly employees that are involved in establishing, implementing and improving safety standards. 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.

Environmental Matters

We and the commercial silica industry are subject to extensive governmental regulation pertaining to matters such as permitting and licensing requirements, plant and wildlife protection, hazardous materials, air and water emissions, and environmental contamination and reclamation. A variety of federal, state and local agencies have established, implement and enforce these regulations.

Federal Regulation

At the federal level, we may be required to obtain permits under Section 404 of the Clean Water Act from the U.S. Army Corps of Engineers for the discharge of dredged or fill material into waters of the United States, including wetlands and streams, in connection with our operations. We also may be required to obtain permits under Section 402 of the Clean Water Act from the Environmental Protection Agency ("EPA") or the Wisconsin Department of Natural Resources ("Wisconsin DNR") or the Texas Commission on Environmental Quality ("TCEQ"), to whom the EPA has delegated local implementation of the permit program, for discharges of pollutants into waters of the United States, including discharges of wastewater or stormwater runoff associated with construction activities. 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 U.S. Clean Air Act 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 U.S. Clean Air Act and comparable state laws and regulations.

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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 damage or injury to property and persons. The 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 Resource Conservation and Recovery Act ("RCRA") and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. The EPA and Wisconsin DNR 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 and thereby delay 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 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 where our Northern White 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, health, and safety requirements applicable to our activities. Failure to comply with environmental laws and regulations may result in the assessment of administrative, civil, and criminal penalties; imposition of investigatory, cleanup, and site restoration costs and liens; the denial or revocation of permits or other authorizations; and the issuance of injunctions to limit or cease operations. 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 damages to persons or property 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.

Texas Production Facility

Our Texas production facility currently operates under permit by rule air permits from the TCEQ.

Stormwater discharges from the production facility is currently permitted under the Texas Pollutant Discharge Elimination System ("TPDES") administered by TCEQ; however, a notice of termination was recently filed and is under review with the TCEQ, and the permit will be terminated shortly as construction activities covered by the permit have ceased and are complete. A new Notice of Intent for the TPDES general construction permit must be filed for any new construction project that may require the general permit.

The site has three septic permits issued by Winkler County. Systems are maintained as appropriate.

Operations are also covered by an Aggregate Production Operations permit issued by TCEQ. The permit will be renewed every year, until operations cease.

The production facility is currently undergoing consultant design and review for submittal of two applications for the permitting of two drinking (potable) water wells and associated drinking water systems. TCEQ must review and approve the well permits and drinking water system permits prior to the production facility construction of the wells and installing and operating the drinking water systems. Once those permits are issued, the production facility would operate the associated drinking water systems in accordance with the public drinking water standards. The permits once issued become permanent until the wells and/or drinking water systems are terminated.

Wisconsin Production Facilities

Our Wisconsin production facilities currently operate under construction and operation air permits from the Wisconsin DNR. Each production facility operates under an operation air permit, with the exception of Wyeville; at our Wyeville facility, we have complied with the construction air permit and have requested an operational air permit from the Wisconsin DNR. All production facilities, have developed and are in compliance with a Fugitive Dust Control Plan and a Malfunction Prevention and Abatement Plan.

Stormwater discharges from our Wisconsin production facilities are permitted under the Wisconsin Pollutant Discharge Elimination System ("WPDES") administered by Wisconsin DNR; and, at our Augusta facility, also under the Eau Claire County Storm Water Management and Erosion Control ordinance. An updated Notice of Intent for the WPDES general construction permit, which would include modifications to the existing storm water management and erosion control structures for an expansion at any production facility is submitted to and approved by the Wisconsin DNR. All Wisconsin production facilities are currently covered by WPDES general construction permits for various projects.

Our Wisconsin production facilities have federal and state certifications and/or permits for the filling and/or taking of wetlands associated with our construction and/or operational activities.

Our mining operations are subject to the conditions of nonmetallic mining permits granted and administered by either the County, City or Township in which we operate. We submit updated nonmetallic mining plans to the relevant regulatory authority as may be required in the event of a proposed expansion of any mining operation.

We utilize groundwater through the installation and operation of high capacity wells, located at our Augusta and Blair facilities. High capacity well permits are issued and administered by the WDNR and are subject to annual (or monthly) withdraw limitations.

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We routinely monitor our water withdrawals, and also utilize a water recycling system to return production water and/or stormwater to minimize the water we need from those high capacity groundwater wells.

Terminal Facilities

We operate our terminal facilities under various federal, state and local authorizations.  Although the list of permits we obtain in order to commence and maintain our operations at each facility vary by location, we are typically required to obtain, among other permits and authorizations, air, land development, local building and highway occupancy permits.  We are also occasionally required to obtain a wetlands permit.

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 U.S. Securities and Exchange Commission ("SEC"). Our reports filed with the SEC are also made available to read and copy at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. You may obtain information about the Public Reference Room by contacting the SEC at 1-800-SEC-0330. 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 the level of drilling and 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.

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:

• 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;

• worldwide political, military, and economic conditions;

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

• commodity prices; and

• development of alternative energy sources.

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 drilling 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.

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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 mining, processing and production facilities 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 of 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 price and availability of transportation;

• 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;

• industrial and transportation related accidents;

• fires, explosions or other accidents;

• difficulty collecting receivables;

• inability of our customers to take delivery;

• difficulties in obtaining and renewing environmental permits;

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

• changes in laws and regulations (or the interpretation 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;

• inability to acquire or maintain necessary permits, licenses or other approvals, including mining or water 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; and

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

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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 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. In addition, a significant shift in demand from the types of raw frac sand product that we produce and sell, to other types of proppants, 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.

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 producers and a larger number of small, regional or local producers. Competition in the industry is based on price, reliability of supply, transportation capabilities, product quality, performance and sand characteristics.

We compete with large, national producers such as U.S. Silica Holdings, Inc., Unimin Corporation, Fairmount Santrol Holdings, Inc., 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 that are located closer to key customers than ours. Should the demand for hydraulic fracturing services decrease, prices in the frac sand market could materially decrease as producers may sell frac sand at below market prices. In addition, oil and natural gas exploration and production companies and other providers of hydraulic fracturing services could acquire their own frac sand reserves, expand their existing frac sand production capacity or otherwise fulfill their own proppant requirements and existing or new frac sand producers could add to or expand their frac sand production capacity, which may negatively impact pricing and demand for our frac sand. Because the markets for our products are typically local, we also compete with smaller regional or local producers. For instance, prior to 2015, there had been an increasing number of small producers servicing the frac sand market due to increased demand for hydraulic fracturing services. In 2018, we anticipate commencement of operations at frac sand production facilities of several national, regional and local producers in the Permian Basin due to expectations of increased demand for frac sand in the Permian Basin. 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 as less-efficient producers exit the market, selling frac sand at below market prices. 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.

The majority of our sales are generated under contracts with companies in the oil and 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, 2018, we have contracted to sell raw frac sand under long-term supply agreements to customers with remaining terms ranging from 12 to 84 months. For the year ended December 31, 2017, we generated 73% of our revenues from sales of frac sand to customers with whom we had long-term contracts.

Some of our customers have exited or could exit the pressure pumping business or have been or could be acquired by other companies that purchase the same products and services we provide from other third-party providers. Our current customers also may seek to acquire frac sand 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 purchased by any customer, could have a material 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. Our customers’ failure to comply with contract terms or our limited enforcement thereof could have a material adverse effect on our business, financial condition and results of operations.

Upon the expiration of our current supply agreements, 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. The demand for frac sand or prevailing prices at the time our current supply agreements expire may render entry into new long-term supply agreements difficult or impossible. 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 a material adverse effect on our business, financial condition and results of operations.

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Our long-term contracts may preclude us from taking advantage of increasing prices for frac sand or 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.

An increase in the supply of raw frac sand could make it more difficult for us to renew or replace our existing contracts on favorable terms, or at all.

If significant new reserves of raw frac sand are discovered and developed, we may be unable to renew or replace our existing contracts at favorable pricing, or at all. Specifically, if frac sand becomes more readily available, our customers may not be willing to enter into long-term contracts, or may demand lower prices, or both, which could have a material adverse effect on our results of operations and cash flows over the long-term.

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 and cash available for distribution.

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 oilfield services 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, results of operations and ability to pay distributions to our unitholders.

We have entered into a Revolving Credit Agreement and Term Loan Credit Facility which contain restrictions and financial covenants that may restrict our business and financing activities.

Our Revolving Credit Agreement and Term Loan 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 Revolving Credit Agreement and Term Loan 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. For example, our Revolving Credit Agreement contains covenants requiring us to maintain a maximum leverage ratio, minimum interest coverage ratio and asset coverage ratio. Additionally, our Revolving Credit Agreement and Term Loan Credit Facility restrict our ability to, among other things:

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

• incur additional indebtedness;

• incur liens on property;

• make certain investments; 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 covenants may be impaired. If we violate any of the restrictions, covenants, ratios or tests in the Revolving Credit Agreement or Term Loan 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 Revolving Credit Agreement and Term Loan 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.

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Our long-term unsecured debt is currently rated by Moody's Investors Service Inc. ("Moody's") and Standard and Poor’s ("S&P"). As of February 15, 2018, the credit rating of the Partnership’s Term Loan Credit Facility 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 Revolving Credit Agreement and Term Loan Credit Facility. As of December 31, 2017, we had $200.0 million of debt outstanding under our Term Loan Credit Facility, with an effective interest rate of 5.41%. Assuming no change in the amount outstanding, the impact on interest expense of a 10% increase or decrease in the average interest rate would be approximately $1.1 million per year. As a result of this variable interest rate debt, our financial condition could be adversely affected by increases in interest rates.

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 additions or modifications to our existing facilities and the construction of new facilities generally involve numerous regulatory, environmental, political and legal uncertainties beyond our control and 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 construct facilities 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 drilling and completion activities to take place in future periods. To the extent we rely on estimates of future levels of drilling and completion activity in any decision to construct facilities, such estimates may prove to be inaccurate because there are numerous uncertainties inherent in forecasting the levels of drilling and completion activity. As a result, new facilities 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.

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 covenants contained in our Revolving Credit Agreement, Term Loan 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.

The majority of our sales are sourced at our production facilities. Any adverse developments at the facilities could have a material 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. 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 a material 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 a material adverse effect on our business, financial condition and results of operations.

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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.

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. 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 U.S. Army Corps of Engineers Wetland Permit is required. At the state level, a series of permits are required related to air quality, wetlands, water quality (waste water, storm water), 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, storm water, erosion control, wellhead protection, road usage and access are all regulated and require permitting to some degree. A non-metallic mining reclamation permit is required. 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, 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. A successful claim 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 action to suspend the access or easement, and any such action could be materially adverse to our business, results of operations or financial condition.

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Federal, state, and local legislative and regulatory initiatives relating to hydraulic fracturing and the potential for related litigation could result in increased costs, additional operating restrictions or delays for our customers, which could cause a decline in the demand for our frac sand and negatively impact 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 controversial and is undergoing increased political and regulatory scrutiny. From time to time, Congress has considered various other 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.

There is also the potential for increased federal regulations governing various environmental aspects of hydraulic fracturing and the oil and gas production industry.  In recent years, the EPA has finalized rules to limit air emissions from the hydraulic fracturing of certain oil and gas wells and to regulate other sources of air emissions from production operations.  The EPA also finalized wastewater effluent guidelines for unconventional oil and gas operations.  Likewise, the Bureau of Land Management ("BLM") finalized rules increasing compliance and disclosure obligations for hydraulic fracturing operations.  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 gas operations.

As noted previously under Item 1, "Business: Environmental Matters", the RCRA and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup 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 gas wastes from regulation as hazardous wastes under RCRA. A loss of the RCRA exclusion for drilling fluids, produced waters and related wastes, if EPA were to eliminate the exclusion, would increase our costs to manage and dispose of the wastes we generate and our customers’ waste management costs and level of drilling activity, either of which could have a significant adverse effect on our results of operations and financial performance.

In addition to federal laws and regulations, various state, local, and foreign governments have implemented, or are considering, increased regulatory oversight of hydraulic fracturing through additional permitting requirements, operational restrictions, disclosure requirements, and temporary or permanent bans on hydraulic fracturing in certain areas such as environmentally sensitive watersheds. Many local governments also have adopted ordinances to severely restrict or prohibit hydraulic fracturing activities within their jurisdictions.

The adoption of new or more stringent laws or regulations at the federal, state, local, or foreign levels imposing reporting obligations on, or otherwise limiting or delaying, the hydraulic fracturing process could make it more difficult to complete oil and natural gas wells, increase our customers’ costs of compliance and doing business, and otherwise adversely affect the hydraulic oil and 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.

As a result of market conditions, 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.

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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, prevention of erosion and 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.

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 3% of our total sales and 11% of our total production costs during the year ended December 31, 2017. 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. 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 comes 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.

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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.

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 recycle a significant percentage in our operating process. As a result, securing water rights and water access 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 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, a water discharge permit may be required to properly dispose of water at our processing sites. The water discharge permitting process is also subject to regulatory discretion, and any inability to obtain the necessary permits could have an adverse effect on our financial condition and results of operations.

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

The performance and quality of our products 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 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 would 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 will 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;

• 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.

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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.

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 evaluating and analyzing sand reserves, building new frac sand processing facilities, maximizing production from such properties, marketing frac sand production, transportation, distribution and developing and executing financing strategies, as well as substantial experience and relationships with participants in the oilfield services and exploration and production 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. We do not maintain key-man life insurance with respect to any of our employees. 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, if our customers are not using our rail transportation services, the ability of our customers to take delivery and, in certain circumstances, constitute a force majeure event under our customer contracts, permitting our customers to suspend taking delivery of and paying for our 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. In addition, rail transportation 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.

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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, or excess railcars 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.

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;

• the cost of acquisitions;

• the amount of unit repurchases we make;

• our debt service requirements and other liabilities;

• fluctuations in our working capital needs;

• 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. 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.

Risks Related to Environmental, Mining and Other Regulation

We and our customers are subject to extensive environmental and health and safety regulations 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.

We are subject to a variety of federal, state, and local regulatory environmental requirements affecting the mining and mineral processing industry, including among others, those relating to employee health and safety, environmental permitting and licensing, air and water emissions, water pollution, waste management, remediation of soil and groundwater contamination, land use, reclamation and restoration of properties, hazardous materials, and natural resources. These laws, regulations, and permits have had, and will continue to have, a significant effect on our business. Some environmental laws impose substantial penalties for noncompliance, and others, such as CERCLA, may impose strict, retroactive, and joint and several liability for the remediation of releases of hazardous substances. Liability under CERCLA, or similar state and local laws, may be imposed as a result of conduct that was lawful at the time it occurred or for the conduct of, or conditions caused by, prior operators or other third parties. Failure to properly handle, transport, store, or dispose of hazardous materials or otherwise conduct our operations in compliance with environmental laws could expose us to liability for governmental penalties, cleanup costs, and civil or criminal liability associated with releases of such materials into the environment, damages to property, or natural resources and other damages, as well as potentially impair our ability to conduct our operations. In addition, 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. Future events, including changes in any environmental requirements (or their interpretation or enforcement) 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 administrative, civil, or 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 services.

We may not be able to comply with any new laws and regulations that are adopted, and any new 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 any new laws and regulations, which could cause our customers to curtail or cease operations. We cannot at this time reasonably estimate our costs of compliance or the timing of any costs associated with any new laws and regulations, or any material adverse effect that any new 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 the MSHA and the 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. We may not be able to comply with any new laws and regulations that are adopted, and any new laws and regulations 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 Federal Mine Safety and Health Act of 1977 and the OSHA of 1970, both of which impose stringent health and safety standards on numerous aspects of our operations.

Our operations are subject to the Federal Mine Safety and Health Act of 1977 ("MSH Act"), as amended by the Mine Improvement and New Emergency Response Act of 2006 as well as the OSHA of 1970 ("OSH Act"), including but not limited to the OSHA Silica Rule published in March 2016. 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 interpretation or enforcement thereof, could have a material adverse effect on our business and financial condition or otherwise impose significant restrictions on our ability to conduct operations.

We and our customers are subject to other extensive regulations, including licensing, 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, we and our customers are subject to extensive governmental regulation on matters such as permitting and licensing requirements, 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.

In order to obtain permits and renewals of permits in the future, we may be required to prepare and present data to governmental authorities pertaining to the potential adverse impact that any proposed 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 delayed or prevented due to community opposition and other factors beyond our control. The denial of a permit essential to our operations or the imposition of conditions with which it is not practicable or feasible to comply could impair or prevent our ability to develop or expand a site. Significant opposition to a permit by neighboring property owners, members of the public, or 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.

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

There are numerous federal proposals and current regulations on GHG emissions, tracking and reporting. Federal agencies have begun directly regulating 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. Those sources subject to PSD permitting would be required to meet "best available control technology" standards for those GHG emissions. The additional regulatory burden may result in the increased costs or additional operating restrictions for our customers.

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 after it has been mined. 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.

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

Our sponsor owns and controls our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner and its affiliates, including our sponsor, have conflicts of interest with us and limited duties, and they may favor their own interests to the detriment of us and our unitholders.

Our sponsor, Hi-Crush Proppants LLC, owns and controls our general partner and appoints all of the directors of our general partner. Although our general partner has a duty to manage us in a manner it believes to be in our best interests, the executive officers and directors of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to our sponsor. Therefore, conflicts of interest may arise between our sponsor or any of its affiliates, including our general partner, on the one hand, and us or any of our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of its affiliates over the interests of our common unitholders. These conflicts include the following situations, among others:

• our general partner is allowed to take into account the interests of parties other than us, such as our sponsor, in exercising certain rights under our partnership agreement, which has the effect of limiting its duty to our unitholders;

• neither our partnership agreement nor any other agreement requires our sponsor to pursue a business strategy that favors us;

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

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

• our general partner determines the amount and timing of any capital expenditure and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders;

• our general partner determines the amount and timing of asset purchases and sales, borrowings, issuances of additional partnership securities and the level of reserves, each of which can affect the amount of cash that is distributed to our unitholders;

• our general partner may cause us to borrow funds in order to permit the payment of cash distributions to our common unitholders, even if the purpose or effect of the borrowing is to make incentive distributions;

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• our partnership agreement permits us to distribute up to $26 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund the incentive distribution rights;

• our general partner determines which costs incurred by it and its affiliates are reimbursable by us;

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

• our general partner intends to limit its liability regarding our contractual and other obligations;

• our general partner may exercise its right to call and purchase common units if it and its affiliates own more than 80% of the common units;

• our general partner controls the enforcement of obligations that it and its affiliates owe to us;

• our general partner decides whether to retain separate counsel, accountants or other advisors to perform services for us; and

• our sponsor may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our sponsor’s incentive distribution rights without the approval of the conflicts committee of the board of directors of our general partner or the unitholders. This election may result in lower distributions to the common unitholders in certain situations.

In addition, we may compete directly with entities in which our sponsor has an interest for acquisition opportunities and potentially will compete with these entities for new and existing customers.

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 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 or the interests of our sponsor to the detriment of our common 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.

Our sponsor may compete with us for investment opportunities.

Affiliates of our general partner, including our sponsor, are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. Our sponsor has had investments in entities that acquired, owned and operated frac sand excavation and processing facilities and our sponsor may make additional investments and acquisitions in the future. These investments and acquisitions may include entities or assets that we would have been interested in acquiring. Therefore, our sponsor may compete with us for investment opportunities. We share our management team with our sponsor, and despite our sponsor’s and management team’s meaningful economic interest in us, the shared management team is under no obligation to offer new investment opportunities to us before offering them to our sponsor, which could have a material adverse impact on our ability to compete.

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Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner or any of its affiliates, including its executive officers and directors and our sponsor. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual or potential conflicts of interest between us and affiliates of our general partner and result in less than favorable treatment of us and our unitholders.

It is our plan to 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 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;

• whether to exercise its call right;

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

• whether to exercise its registration rights;

• whether to elect to reset target distribution levels; 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

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(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.

Our sponsor may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to its incentive distribution rights, without the approval of the conflicts committee of the board of directors of our general partner or the holders of our common units. This could result in lower distributions to holders of our common units.

Our sponsor has the right, as the initial holder of our incentive distribution rights, at any time when it has received incentive distributions at the highest level to which it is entitled (50%) for the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our distributions at the time of the exercise of the reset election. Following a reset election by our sponsor, the minimum quarterly distribution will be adjusted to equal the reset minimum quarterly distribution and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.

If our sponsor elects to reset the target distribution levels, it will be entitled to receive a number of common units. The number of common units to be issued to our sponsor will equal the number of common units that would have entitled the holder to an aggregate quarterly cash distribution in the quarter prior to the reset election equal to the distribution to our sponsor on the incentive distribution rights in the quarter prior to the reset election. We anticipate that our sponsor would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion. It is possible, however, that our sponsor could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its incentive distribution rights and may, therefore, desire to be issued common units rather than retain the right to receive incentive distributions based on the initial target distribution levels. This risk could be elevated if our incentive distribution rights have been transferred to a third party. As a result, a reset election may cause our common unitholders to experience a reduction in the amount of cash distributions that our common unitholders would have otherwise received had we not issued new common units to our sponsor in connection with resetting the target distribution levels.

Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors, which could reduce the price at which our common units will trade.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders have no right on an annual or ongoing basis to elect our general partner or its board of directors. The board of directors of our general partner, including the independent directors, is chosen entirely by our sponsor, as a result of it owning our general partner, and not by our unitholders. Unlike publicly-traded corporations, we do not conduct annual meetings of our unitholders to elect directors or conduct other matters routinely conducted at annual meetings of stockholders of corporations. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

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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The incentive distribution rights held by our sponsor may be transferred to a third party without unitholder consent.

Our sponsor may transfer the incentive distribution rights to a third party at any time without the consent of our unitholders. If our sponsor transfers the incentive distribution rights to a third party but retains its ownership interest in our general partner, our general partner may not have the same incentive to grow our partnership and increase quarterly distributions to unitholders over time as it would if our sponsor had retained ownership of the incentive distribution rights. For example, a transfer of incentive distribution rights by our sponsor could reduce the likelihood of our sponsor accepting offers made by us relating to assets owned by it, as it would have less of an economic incentive to grow our business, which in turn would impact our ability to grow our asset base.

Our general partner has a call right that may require unitholders to sell their common units at an undesirable time or price.

If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price equal to the greater of (1) the average of the daily closing price of the common units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed and (2) the highest per-unit price paid by our general partner or any of its affiliates for common units during the 90-day period preceding the date such notice is first mailed. As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return or a negative return on their investment. Unitholders may also incur a tax liability upon a sale of their units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the limited call right. There is no restriction in our partnership agreement that prevents our general partner from issuing additional common units and exercising its call right. If our general partner exercised its limited call right, the effect would be to take us private and, if the units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Exchange Act. As of December 31, 2017, our sponsor did not own any of our common units.

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;

• because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;

• 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.

Cost reimbursements due to our general partner and its affiliates for services provided to us or on our behalf will reduce cash available for distribution to our unitholders. The amount and timing of such reimbursements will be determined by our general partner.

Prior to making any distribution on the common units, we will reimburse our general partner and its affiliates for all expenses they incur and payments they make on our behalf. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates will reduce the amount of cash available for distribution to our unitholders.

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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.

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.

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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.

Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the target distribution amounts may be adjusted to reflect the impact of that law or interpretation on us.

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

The present federal income tax treatment of publicly-traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial 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. Although there is no current legislative proposal, a prior legislative proposal would have eliminated the Qualifying Income Exception upon which we rely for our treatment as a partnership for federal income tax purposes. 

In addition, on January 24, 2017, final regulations regarding which activities give rise to qualifying income within the meaning of Section 7704 of the Code (the "Final Regulations") were published in the Federal Register. The Final Regulations are effective as of January 19, 2017, and apply to taxable years beginning on or after January 19, 2017. We do not believe the Final Regulations affect our ability to be treated as a partnership for federal income tax purposes. However, there are no assurances that the Final Regulations will not be revised to take a position that is contrary to our interpretation of the current law.

However, any modification to the federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet Qualifying Income Exception. In addition, such changes may affect or cause us to change our business activities, affect the tax considerations of an investment in us, change the character or treatment of portions of its income, or otherwise adversely affect an investment in our common units.  We are unable to predict whether any of these changes or any other proposals will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units and the amount of cash available for distribution to our unitholders. 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.

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

Because our unitholders are treated as partners to whom we allocate taxable income that could be different in amount than the cash we distribute, they are required to pay federal income taxes and, in some cases, state and local income taxes on their share of our taxable income whether or not they receive cash distributions from us. For example, 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. 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.

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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. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture of depreciation and depletion deductions and certain other items. 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 persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.

Investments 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. Further, with respect to taxable years beginning after December 31, 2017, a tax-exempt entity with more than one unrelated trade or business (including by attribution from investment in a partnership such as ours that is engaged in one or more unrelated trade or business) 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.

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 interest 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.

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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.

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 and our general partner because the costs will reduce our cash available for distribution.

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 certain deductions for depreciation of capital additions gain or loss realized on a sale or other disposition of our assets and, 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.

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.

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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 are subject to state and local taxes and return filing requirements in states where they do not live as a result of investing in our common units.

In addition to federal income taxes, our unitholders are subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if they do not live in any of those jurisdictions. As of December 31, 2017, we own assets and conduct business in several states. Most of these states currently impose a personal income tax and income taxes on corporations and other entities. Unitholders may be required to file state and local income tax returns and pay state and local income taxes in these states. Further, unitholders may be subject to penalties for failure to comply with those requirements. 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.

ITEM 1B. UNRESOLVED STAFF COMMENTS

Not applicable.

ITEM 2. PROPERTIES

Hi-Crush Services LLC, a subsidiary of our sponsor, leases office space for our principal executive offices in Houston, Texas. As of December 31, 2017, we operated five production facilities located in Wisconsin and Texas, and we own all associated land. In addition, we own or operate 12 terminal locations, lease or own 4,253 railcars used to transport sand from origin to the terminal and we lease 1,249 containers used to transport sand from the terminal to the wellsite. Substantially all of our owned assets are pledged as security under our Revolving Credit Agreement and Term Loan Credit Facility; please see Item 7, "Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources".

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. During the year ended December 31, 2017, the Wyeville facility produced and delivered 2,111,358 tons of frac sand. As of December 31, 2017, the total cost of our plant and equipment was $62.3 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.

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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. As a result of market conditions, the Augusta facility was temporarily idled in October 2015 until production resumed at reduced capacity levels in September 2016. We resumed production at rates near full capacity in April 2017. During the year ended December 31, 2017, the Augusta facility produced and delivered 1,802,126 tons of frac sand. As of December 31, 2017, the total cost of the Augusta facility and equipment was $110.1 million. The plant is in good physical condition and includes modern equipment powered by natural gas and electricity.

All of the product from the 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, 2017, the Blair facility produced and delivered 2,499,831 tons of frac sand. As of December 31, 2017, the total cost of Blair facility and equipment was $103.3 million. The plant is in good physical condition and includes modern equipment powered by natural gas and electricity.

All of the product from the Blair facility is shipped by rail from approximately 45,000 feet of track that connects our facility to a Canadian National 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.

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 Railroad mainline.

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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, 2017, the Whitehall facility produced and delivered 1,740,646 tons of frac sand. As a result of market conditions, the Whitehall facility was temporarily idled during the second quarter of 2016 and resumed production in March 2017. As of December 31, 2017, the total cost of Whitehall facility and equipment was $111.9 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 34,000 feet of track that connects our facility to a Canadian National 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.

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 1,447 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 Railroad mainline.

Kermit Facility

We completed construction of the Kermit facility in July 2017. The Kermit facility has an annual processing capacity of approximately 3,000,000 tons of frac sand per year. During the year ended December 31, 2017, the Kermit facility produced and delivered 913,623 tons of frac sand. As of December 31, 2017, the total cost of Kermit facility and equipment was $50.3 million. The plant is in good physical condition and includes modern equipment powered by natural gas and electricity.

All of the product from our Kermit facility is delivered by truck to the wellsite from five on-site silos with 15,000 tons of storage capacity.

The following table summarizes certain of the key characteristics of our Kermit 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 1,226 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	Five on-site silos with 15,000 tons of storage capacity and infrastructure capable of direct loading into trucks.

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Terminals

As of December 31, 2017, we own or operate 12 terminal locations as summarized in the following table:

Location	Storage Capabilities	Railroad	Unit Train Capable	On-site Laboratory
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		þ
Minerva, OH	Rail/Silo	Ohio-Rail Corp.	þ	þ
Mingo Junction, OH	Rail/Silo	Norfolk Southern	þ	þ
Odessa, TX	Rail/Silo	Union Pacific Railroad	þ
Pecos, TX	Rail/Silo	Union Pacific Railroad	þ	þ
Smithfield, PA	Rail/Silo	Southwest Pennsylvania Railroad	þ	þ
Wellsboro, PA	Rail/Silo	Wellsboro & Corning Railroad	þ	þ

(a) Terminal is temporarily idled.

As of December 31, 2017, we leased or owned 4,253 railcars used to transport sand from origin to the terminal and we lease 1,249 containers used to transport sand from the terminal to the wellsite.

Sand Reserves

Summary of Reserves

The following table provides a summary of our facilities as of December 31, 2017:

Mine/Plant Location	Owned/Leased	Area (in acres)	Proven Reserves (in thousands of tons)	Primary End Markets Served
Wyeville, WI	Owned	971	74,072	Oil and gas proppants
Augusta, WI	Owned	1,187	38,582	Oil and gas proppants
Blair, WI	Owned	1,285	114,922	Oil and gas proppants
Whitehall, WI	Owned	1,447	78,157	Oil and gas proppants
Kermit, TX	Owned	1,226	103,580	Oil and 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, 2017, 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.

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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 or our sponsor 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.

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 U.S. Federal Mine Safety and Health Administration ("MSHA") regulations. For both health and safety issues, extensive training is provided to employees. We have safety meetings at our plants made up of salaried and hourly employees. We perform annual internal health and safety audits and conduct semi-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 Federal Mine Safety and Health Act of 1977 (the "Mine Act"). MSHA inspects our mines on a regular basis and issues various citations and orders when it believes a violation has occurred under the Mine Act. 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."

The following table sets forth the range of high and low sales prices per unit for our common units as reported by the NYSE, and the quarterly cash distributions for the indicated periods:

Sales Price Per Common Units
For the Quarter Ended	High		Low
March 31, 2016	$	7.16	$	3.55
June 30, 2016	$	13.10	$	4.25
September 30, 2016	$	16.81	$	10.55
December 31, 2016	$	20.95	$	13.75
March 31, 2017	$	23.30	$	13.55
June 30, 2017	$	18.25	$	9.30
September 30, 2017	$	11.40	$	7.25
December 31, 2017	$	11.61	$	8.60

Cash Distributions To Limited Partner Unitholders
For the Quarter Ended	Record Date	Payment Date	Amount per Limited Partner   Unit
September 30, 2017	October 31, 2017	November 14, 2017	$	0.1500
December 31, 2017	February 1, 2018	February 13, 2018	$	0.2000

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.

As of December 31, 2017, there were 89,009,188 common units outstanding held by approximately 31,037 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

There is no guarantee that we will distribute quarterly cash distributions to our unitholders. We do not have a legal or contractual obligation to pay quarterly distributions at any rate. Our cash distribution policy is subject to certain restrictions and may be changed at any time. The reasons for such uncertainties in our stated cash distribution policy include the following factors:

• Our cash distribution policy is subject to the terms of our Revolving Credit Agreement and Term Loan Credit Facility, which contain financial tests and covenants that we must satisfy. The Revolving Credit Agreement requires compliance with customary financial covenants, which are a maximum leverage ratio of 3.25x, a minimum interest coverage ratio of 2.5x and an asset coverage ratio of 1.5x. Should we not be in compliance or if we are otherwise in default under either facility, we will be prohibited from making cash distributions to our unitholders notwithstanding our stated cash distribution policy.

• Our general partner has the authority to establish cash reserves for the prudent conduct of our business, including for future cash distributions to our unitholders, and the establishment of or increase in those reserves could result in a reduction in cash distributions from levels we currently anticipate pursuant to our stated cash distribution policy. Our partnership agreement does not set a limit on the amount of cash reserves that our general partner may establish. Any decision to establish cash reserves made by our general partner in good faith will be binding on our unitholders.

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• Prior to making any distribution on the common units, we reimburse our general partner and its affiliates for all direct and indirect expenses they incur on our behalf. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our partnership agreement provides that our general partner determines in good faith the expenses that are allocable to us. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates reduces the amount of cash available for distribution to pay distributions to our unitholders.

• Even if our cash distribution policy is not modified or revoked, the amount of distributions we pay under our cash distribution policy and the decision to make any distribution is determined by our general partner.

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

• We may lack sufficient cash to pay distributions to our unitholders due to cash flow shortfalls attributable to a number of operational, commercial or other factors as well as increases in our operating or general and administrative expenses, principal and interest payments on our outstanding debt, tax expenses, working capital requirements and anticipated cash needs. While our general partner may cause us to borrow funds in order to permit the payment of cash distributions on our common units and incentive distribution rights, it has no obligation to cause us to do so.

• If we make distributions out of capital surplus, as opposed to operating surplus, any such distributions would constitute a return of capital.

• Our ability to make distributions to our unitholders depends on the performance of our subsidiaries and their ability to distribute cash to us. The ability of our subsidiaries to make distributions to us may be restricted by, among other things, the provisions of future indebtedness, applicable state limited liability company laws and other laws and regulations.

Distribution Policy

Intent to Distribute a Quarterly Distribution

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, including payments to our general partner and its affiliates.

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. However, it does contain provisions intended to motivate our general partner to make steady, increasing and sustainable distributions over time.

General Partner Interest

Our general partner owns a non-economic general partner interest in us, which does not entitle it to receive cash distributions. However, our general partner may in the future own common units or other equity securities in us and will be entitled to receive distributions on any such interests.

Incentive Distribution Rights

Our sponsor currently holds incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 50.0%, of the cash we distribute from operating surplus in excess of $0.54625 per unit per quarter. The maximum distribution of 50.0% does not include any distributions that our sponsor may receive on any limited partner units that it owns.

Percentage Allocations of Distributions From Operating Surplus

The following table illustrates the percentage allocations of distributions from operating surplus between the unitholders and our sponsor (as the holder of our incentive distribution rights) based on the specified target distribution levels. The amounts set forth under the column heading "Marginal Percentage Interest in Distributions" are the percentage interests of our sponsor (as the holder of our incentive distribution rights) and the unitholders in any distributions from operating surplus we distribute up to and including the corresponding amount in the column "Total Quarterly Distribution Per Unit." The percentage interests set forth below assume our sponsor has not transferred its incentive distribution rights. There are no arrearages on common units.

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		Marginal Percentage Interest in Distribution
	Total Quarterly Distribution Target Amount	Unitholders		Sponsor (as Holder of our Incentive Distribution Rights)
First Target Distribution	Up to $0.54625	100.0	%	—	%
Second Target Distribution	$0.54625 to $0.59375	85.0	%	15.0	%
Third Target Distribution	$0.59375 to $0.7125	75.0	%	25.0	%
Thereafter	$0.7125 and above	50.0	%	50.0	%

Equity Compensation Plan Information

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, 2017.

Recent Sales of Unregistered Securities

On March 3, 2017, in connection with our acquisition of Permian Basin Sand Company, LLC, we issued 3,438,789 common units to 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. 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

The following table presents information with respect to repurchases of common units made by the Partnership during the three months ended December 31, 2017(in thousands, except number of units and per unit amounts):

	Total Number of Units Purchased	Average Price Paid Per Unit Including Commission		Total Number of Units Purchased as Part of Publicly Announced Plans or Programs	Maximum Number (or approximate dollar value) of Units that May Yet be Purchased Under the Plans or Programs (a)
October 1, 2017 to October 31, 2017	—	$	—	—	$	100,000
November 1, 2017 to November 30, 2017	1,720,534	$	9.70	1,720,534	$	83,306
December 1, 2017 to December 31, 2017	309,629	$	10.68	309,629	$	80,000
	2,030,163			2,030,163

(a) 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. During the fourth quarter of 2017, the Partnership repurchased 2,030,163 common units for a total cost of $20,000.

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, 2017.

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ITEM 6. SELECTED FINANCIAL DATA

The Partnership's historical financial data has been recast to include 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,
	2017			2016			2015			2014			2013
Statement of Operations Data:
Revenues	$	602,623		$	204,430		$	339,640		$	386,547		$	178,970
Production costs	133,769			54,187			76,996			22,663			33,841
Logistic costs	304,579			134,121			162,629			179,516			54,846
Depreciation, depletion and amortization	29,449			17,032			16,613			12,002			7,197
Cost of goods sold	467,797			205,340			256,238			214,181			95,884
Gross profit (loss)	134,826			(910		)	83,402			172,366			83,086
Operating costs and expenses:
General and administrative	39,008			35,501			27,811			28,038			19,450
Impairments and other expenses	865			34,025			25,659			11			194
Accretion of asset retirement obligations	458			430			394			265			228
Other operating income	(3,554		)	—			(12,310		)	—			—
Income (loss) from operations	98,049			(70,866		)	41,848			144,052			63,214
Other income (expense):
Earnings from equity method investments	75			—			—			—			—
Interest expense	(11,258		)	(13,653		)	(14,126		)	(10,111		)	(3,671		)
Loss on extinguishment of debt	(4,332		)	—			—			—			—
Net income (loss)	$	82,534		$	(84,519	)	$	27,722		$	133,941		$	59,543
Earnings (loss) per limited partner unit:
Limited partner units - basic	$	0.97		$	(1.64	)	$	0.73		$	3.09		$	2.08
Limited partner units - diluted	$	0.96		$	(1.64	)	$	0.73		$	3.00		$	2.08
Distributions per limited partner unit	$	0.3500		$	—		$	1.1500		$	2.4000		$	1.9500
Statement of Cash Flow Data:
Net cash provided by (used in):
Operating activities	$	96,269		$	(27,985	)	$	100,748		$	103,347		$	64,080
Investing activities	(470,022		)	(127,840		)	(126,526		)	(396,055		)	(138,551		)
Financing activities	374,894			147,104			33,509			277,611			84,581
Other Financial Data:
Adjusted EBITDA (a)	$	129,186		$	(18,400	)	$	84,944		$	159,470		$	73,033
Capital expenditures (b)	122,032			44,011			127,217			171,805			43,596
Operating Data:
Total sand sold (in tons)	8,938,713			4,253,746			5,003,702			4,584,811			2,520,119
Average price per ton sold	$	66.94		$	47.65		$	62.05		$	70.46		$	65.64
Sand produced and delivered (in tons)	9,067,584			4,207,044			5,008,960			4,198,656			2,241,199
Contribution margin per ton sold	$	18.38		$	3.79		$	19.99		$	40.21		$	35.82
Balance Sheet Data (at period end):
Cash	$	5,662		$	4,521		$	13,242		$	5,511		$	20,608
Total assets	1,123,140			659,201			669,738			609,617			394,343
Long-term debt	194,462			193,458			246,783			198,364			138,250
Total liabilities	327,505			356,994			517,338			420,319			211,648
Equity	795,635			302,207			152,400			189,298			182,695

(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 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 Augusta, Blair, Whitehall and PDQ Properties LLC 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)	2017			2016			2015			2014			2013
Net income (loss)	$	82,534		$	(84,519	)	$	27,722		$	133,941		$	59,543
Depreciation and depletion expense	29,456			17,039			15,684			10,232			6,132
Amortization expense	1,681			1,682			2,620			5,186			3,687
Interest expense	11,258			13,653			14,126			10,111			3,671
EBITDA	124,929			(52,145		)	60,152			159,470			73,033
Non-cash impairments of long-lived assets and goodwill	—			33,745			24,792			—			—
Earnings from equity method investments	(75		)	—			—			—			—
Loss on extinguishment of debt	4,332			—			—			—			—
Adjusted EBITDA	129,186			(18,400		)	84,944			159,470			73,033
Less: Cash interest paid	(9,867		)	(11,787		)	(11,833		)	(8,847		)	(3,123		)
Less: Maintenance and replacement capital expenditures, including accrual for reserve replacement (a)	(13,742		)	(5,680		)	(6,762		)	(5,668		)	(3,026		)
Add: Accretion of asset retirement obligations	458			430			394			265			228
Add: Unit-based compensation	5,714			2,620			2,983			1,470			—
Distributable cash flow	111,749			(32,817		)	69,726			146,690			67,112
Adjusted for: Distributable cash flow attributable to assets contributed by the sponsor, prior to the period in which the contribution occurred (b)	1,247			1,641			(900		)	(18,796		)	923
Distributable cash flow attributable to Hi-Crush Partners LP	112,996			(31,176		)	68,826			127,894			68,035
Less: Distributable cash flow attributable to holders of incentive distribution rights	—			—			(1,311		)	(18,401		)	—
Distributable cash flow attributable to limited partner unitholders	$	112,996		$	(31,176	)	$	67,515		$	109,493		$	68,035

(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. 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 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 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 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 premier provider of proppant and logistics solutions to the North American energy industry. Our portfolio of production facilities is capable of producing 13,430,000 tons per year of high-quality monocrystalline sand, a specialized mineral used as a proppant during the well completion process, necessary to facilitate the recovery of hydrocarbons from oil and natural gas wells. Our Wisconsin production facilities' direct access to major U.S. railroads and our strategically located owned and operated in-basin terminals as well as our Texas production facility positions us within close proximity to significant activity in all major oil and gas basins. Our integrated distribution system, including our PropStream^TM logistics service, delivers proppant the "last mile" into the blender.

On January 31, 2013 and April 8, 2014, the Partnership entered into agreements with our sponsor which ultimately resulted in the acquisition of 98.0% of the common equity interests in Hi-Crush Augusta LLC ("Augusta"), the entity that owns a 1,187-acre facility with integrated rail infrastructure, located in Eau Claire County, Wisconsin (the "Augusta facility").

Our June 10, 2013, acquisition of D & I Silica, LLC ("D&I") transformed us into an integrated Northern White frac sand producer, transporter, marketer and distributor. At the time of the acquisition, D&I was the largest independent frac sand supplier to the oil and gas industry drilling in the Marcellus and Utica shale plays.

On August 9, 2016, the Partnership entered into a contribution agreement with the sponsor to acquire all of the outstanding membership interests in Hi-Crush Blair LLC ("Blair"), the entity that owned our sponsor's 1,285-acre facility with integrated rail infrastructure, located near Blair, Wisconsin (the "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 "Blair Contribution"). The Partnership completed the acquisition of the Blair facility on August 31, 2016.

On February 23, 2017, the Partnership entered into a contribution agreement with our sponsor to acquire all of the outstanding membership interests in Hi-Crush Whitehall LLC ("Whitehall"), the entity that owned our sponsor’s 1,447-acre facility with integrated rail infrastructure, located near Independence, Wisconsin and Whitehall, Wisconsin (the "Whitehall facility"), the remaining 2.0% equity interest in Augusta, and all of the outstanding membership interests in PDQ Properties LLC (together, the "Other Assets"), for $140,000 in cash and up to $65,000 of contingent consideration over a two-year period (the "Whitehall Contribution"). The Partnership completed this acquisition on March 15, 2017.

On March 3, 2017, the Partnership completed an acquisition of Permian Basin Sand Company, LLC ("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. 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, within 75 miles of significant Delaware and Midland Basin activity.

Our Assets and Operations

We own and operate the 971-acre facility with approximately 32,000 feet of integrated rail infrastructure, located in Wyeville, Wisconsin (the "Wyeville facility") and, as of December 31, 2017, contained 74.1 million tons of proven recoverable reserves of frac sand. The Wyeville facility, completed in June 2011 and expanded in 2012, has an annual processing capacity of approximately 1,850,000 tons of frac sand per year.

We own and operate the 1,187-acre Augusta facility with approximately 38,000 feet of integrated rail infrastructure and, as of December 31, 2017, contained 38.6 million tons of proven recoverable reserves of frac sand. We completed construction of the Augusta facility in June 2012 and expanded in 2014. The Augusta facility has an annual processing capacity of approximately 2,860,000 tons of frac sand per year. During September 2016, the Partnership resumed production at its Augusta facility, which was temporarily idled in October 2015 as a result of market conditions.

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We own and operate the 1,285-acre Blair facility, with approximately 45,000 feet of integrated rail infrastructure and, as of December 31, 2017, contained 114.9 million tons of proven recoverable reserves of frac sand. 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.

We own and operate the 1,447-acre Whitehall facility with approximately 34,000 feet of integrated rail infrastructure and, as of December 31, 2017, contained 78.2 million tons of proven recoverable reserves of frac sand. The Whitehall facility, completed in the third quarter of 2014, is capable of delivering approximately 2,860,000 tons of frac sand per year. As a result of market conditions, the Whitehall facility was temporarily idled during the second quarter of 2016 and resumed production in March 2017.

As of 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. The 1,226-acre Kermit facility is located near Kermit, Texas, strategically positioned in the Permian Basin, within 75 miles of significant Delaware and Midland Basin activity. As of December 31, 2017, the reserves contained 103.6 million tons of proven recoverable reserves of frac sand.

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 of API specifications with regard to crush strength, turbidity and roundness and sphericity. Based on third-party reserve reports by John T. Boyd, we have an implied average reserve life of 30 years, assuming production at the rated capacity of 13,430,000 tons of frac sand per year.

As of December 31, 2017, we own or operate 12 terminal locations throughout Colorado, Pennsylvania, Ohio, New York and Texas, of which two are temporarily idled and seven are capable of accommodating unit trains. Our terminals include approximately 109,000 tons of rail storage capacity and approximately 140,000 tons of silo storage capacity.

We are continuously looking 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, 2017, we leased or owned 4,253 railcars used to transport sand from origin to destination and managed a fleet of 2,404 additional railcars dedicated to our facilities by our customers or the Class I railroads. In addition, the Partnership has placed orders for an additional 700 leased railcars, which are scheduled to be delivered during the first half of 2018.

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 proprietary conveyor system, PropBeast^®, significantly reduces noise and dust emissions due to its fully enclosed environment. As of December 31, 2017, we owned 22 PropBeast conveyors and leased 1,249 containers from PropX. In addition, the Partnership received an additional 126 containers in the first quarter of 2018.  

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 2018 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 based on market pricing. Our contracts for sand sourced from our Kermit facility 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 rail origin, terminal or wellsite.

We generate service revenues through the performance of PropStream, transload and terminaling, railcar storage, silo storage and other services performed on behalf of our customers.

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

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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 processing facility and move the sand from our wet plant to our dry plant. 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 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. During the third quarter of 2016, the Partnership entered into an agreement to terminate certain existing royalty agreements for $6,750, of which $3,375 was paid during each of September 2017 and 2016. As a result of this agreement, the Partnership reduced its ongoing future royalty payments to the applicable counterparties for each ton of frac sand that is excavated, processed and sold to the Partnership’s customers. We currently pay an aggregate rate up to $5.15 per ton of sand excavated from our Wisconsin facilities, delivered to and paid for by our customers. No royalties are due on the sand extracted from our Kermit facility.

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 freight charges, fuel surcharges, railcar lease expense, trucking and switch fees. 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.

General and Administrative Costs

We incur general and administrative costs related to our corporate operations. Under our partnership agreement and the services agreement with our sponsor and our general partner, our sponsor has discretion to determine, in good faith, the proper allocation of costs and expenses to us for its services, including expenses incurred by our general partner and its affiliates on our behalf. The allocation of such costs is based on management’s best estimate of time and effort spent on the respective operations and facilities. Under these agreements, we reimburse our sponsor for all direct and indirect costs incurred on our behalf.

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 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.  

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.

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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 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:

• 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 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. The Partnership resumed production at the Whitehall facility in March 2017, resulting in an increase in volumes produced and delivered during 2017 as compared to 2016, and a decrease in volumes during 2016 as compared to 2015.

• 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 2017 as compared to 2016 and a decrease in volumes during 2016 as compared to 2015.

• We completed construction of our Blair facility in March 2016. We completed construction of our Blair facility in March 2016. Accordingly, our financial statements through December 31, 2015 do not include any sales or operations generated from our Blair facility.

• During 2015 and 2016, we provided significant price concessions and waivers under our contracts. Beginning in August 2014 and continuing through the second quarter of 2016, oil and natural gas prices declined dramatically and persisted at levels well below those experienced during the middle of 2014. In 2015, as a result of the market dynamics existing during the year and continuing in the first half of 2016, we provided market-based pricing to our contract customers and/or waivers of minimum volume purchase requirements, in certain circumstances in exchange for, among other things, additional term and/or volume. Market pricing for sand began to stabilize late in the third quarter of 2016, and we continue to deliver sand at market prices.

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• 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 through September 30, 2016 do not include any sales or operations generated from PropStream.

• 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.

• Our outstanding balance under the Prior Revolving Credit Agreement was paid in full as of June 30, 2016. As of December 31, 2016, we did not have any indebtedness outstanding under our Prior Revolving Credit Agreement. As a result, our interest expense decreased during 2017 and 2016 as compared to 2015.

• 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.

• We received a contract settlement payment in 2015. In December 2015, we received a settlement payment of $22,500 for past and future obligations under a customer contract. Of the total contact settlement payment, $10,190 was recognized as revenue related to make-whole payments and the remainder as other operating income.

• We impaired the intangible value associated with a third party supply agreement. During the year ended December 31, 2015, we completed an impairment assessment of the intangible asset associated with a third party supply agreement (the "Sand Supply Agreement").  Given market conditions, coupled with our ability to internally produce sand on more favorable terms, we determined that the fair value of the agreement was less than its carrying value, resulting in an impairment of $18,606.

• We realized asset impairments and other expenses during 2015. As a result of market conditions, during the year ended December 31, 2015, we elected to temporarily idle five destination transload facilities and three rail origin transload facilities.  In addition, to consolidate our administrative functions, we closed down a regional office facility.  As a result of these actions, we recognized an impairment of $6,186 related to the write-down of transload and office facilities assets to their net realizable value, and severance, retention and relocation costs of $571 for affected employees.

Market Conditions

Exploration and production activity throughout 2017 increased, as demonstrated by the improvements in the reported Baker Hughes land rig count in the United States from a low average of 380 rigs in May 2016 to 909 rigs as of December 31, 2017. While still well below the high average of 1,859 rigs in November 2014, drilling and completions efficiencies have continued to improve such that the energy industry views approximately 900 rigs as being capable of generating the same amount of completion and service intensity as 2,000 rigs did in 2014. The energy industry's outlook for the 2018 activity levels includes oil and natural gas prices that would support continued rig count averages of 1,000 rigs in 2018. Well completion activity would similarly be expected to increase over the next several quarters, which, when coupled with higher usage of frac sand per well, should result in an increased strong positive influence on demand for raw frac sand.

We expect frac sand supply to lag growth in demand over the coming months and quarters. While stated capacity may exceed the expectations for frac sand demand, available industry capacity is constrained due to 1) availability of the grades of sand that are currently in demand, 2) general operating conditions and normal downtime and 3) logistics constraints. The industry is adding capacity over the next 12 to 18 months, particularly in the Permian Basin; however, we do not expect such supply to be available in the volume, grades or timeframe needed to efficiently meet the increasing demand. The advent of "In-Basin" sand supply available closer to the wellsite in the Permian Basin, may cause a shift in supply over time from Northern White sand to In-Basin sand supply. However, we believe this shift will be 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 grades 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.

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Beginning in the fourth quarter of 2016 and continuing throughout 2017, rig count and well completion activity increased meaningfully over levels experienced in the middle of 2016. Demand for proppant increased at a higher rate than well completion activity due to continued increases in frac sand intensity per well. During the same time frame, frac sand supply increased at a slower rate, even with the resumption of operations at several previously idled mines. This dynamic led to a dramatic increase in frac sand pricing during the first quarter of 2017, which has continued to increase throughout 2017 and into 2018.

Given the energy industry's outlook for 2018 activity levels, we expect well completion activity to continue to improve over the next several quarters, which, coupled with higher usage of frac sand per well, should result in an increased positive influence on demand for raw frac sand. Supply of raw frac sand is expected to increase in 2018 as development of new Permian Basin production facilities are completed and ramp up operations. However, we believe this new supply will lag increases in demand, presenting continued positive impact on supply and demand dynamics, and therefore potentially preserving a constructive environment for pricing stability or improvement.

As we began to see increasing demand for frac sand in 2017, we prepared our idled facilities, Whitehall and the Augusta wet plant, to resume operations late in the first quarter of 2017. During the first quarter of 2017, we fully re-staffed our facilities and removed all railcars from long-term storage. In the third quarter of 2017, we commenced operations at our fifth plant, the Kermit facility in the Permian Basin. During the past two years, we continued to invest in terminal operations to reduce our cost of delivering sand in-basin and completed construction of our Pecos terminal in October 2017. Currently all five of our frac sand production facilities are in operation.

The following table presents sales, volume and pricing comparisons for the fourth quarter of 2017, as compared to the third quarter of 2017:

	Three Months Ended
	December 31,			September 30,						Percentage
	2017			2017			Change			Change
Revenues generated from the sale of frac sand (in thousands)	$	212,432		$	167,473		$	44,959		27	%
Tons sold	2,985,115			2,456,195			528,920			22	%
Percentage of volumes sold FOB plant	42		%	39		%	3		%	8	%
Percentage of volumes sold in-basin via our terminal network	43		%	51		%	(8		)%	(16	)%
Percentage of volumes sold at the wellsite	15		%	10		%	5		%	50	%
Average price per ton sold	$	71		$	68		$	3		4	%

Tons sold during the fourth quarter of 2017 were 22% higher than the third quarter of 2017 primarily due to a full quarter of production at our Kermit facility in the fourth quarter of 2017, coupled with additional market demand increases due to rig count and well completion activity. The increased volumes coupled with increased pricing led to the increase in frac sand revenues as compared to the prior quarter.

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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, 2017, 2016 and 2015.

	Year Ended December 31,
	2017			2016			2015
Revenues	$	602,623		$	204,430		$	339,640
Costs of goods sold
Production costs	133,769			54,187			76,996
Logistic costs	304,579			134,121			162,629
Depreciation, depletion and amortization	29,449			17,032			16,613
Gross profit (loss)	134,826			(910		)	83,402
Operating costs and expenses	36,777			69,956			41,554
Income (loss) from operations	98,049			(70,866		)	41,848
Other income (expense)
Earnings from equity investment methods	75			—			—
Interest expense	(11,258		)	(13,653		)	(14,126		)
Loss on extinguishment of debt	(4,332		)	—			—
Net income (loss)	$	82,534		$	(84,519	)	$	27,722

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	%
Percentage of volumes sold FOB plant	38		%	46		%	(8		)%	(17	)%
Percentage of volumes sold in-basin via our terminal network	51		%	53		%	(2		)%	(4	)%
Percentage of volumes sold at the wellsite	11		%	1		%	10		%	1,000	%
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 dramatically improving market conditions as well as increased production capacity availability following 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. The average sales price between the two periods differs due to changes in industry market conditions, including generally short supply of frac sand with increasing demand in 2017 compared to excess supply of frac sand with declining demand in 2016, and the resulting sales price trends, as well as the impact of the mix in pricing of volumes sold FOB plant, in-basin via our terminal network or at the wellsite. Pricing in 2017 was rising throughout the year and. in general, was significantly higher than the 2016, during which we provided discounted pricing for contract customers given market conditions at the time. Other revenues related to PropStream services, transload and terminaling, railcar storage, silo storage and other services was $4,268 and $1,721 for the twelve months endedDecember 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 production 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 $36,777 primarily attributable to general and administrative expenses of $39,008 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 $943 associated with the Whitehall Contribution and other business development activities.

For the year ended December 31, 2016, we incurred total operating costs and expenses of $69,956, which included general and administrative expenses of $35,501 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 $850 in transaction costs associated with the Blair Contribution, $407 in other business development costs and an $8,236 increase in bad debt expense associated 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 $11,258 and $13,653 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 $82,534 for the year ended December 31, 2017, compared to a net loss of $(84,519) for the year ended December 31, 2016.

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Year Ended December 31, 2016 Compared to Year Ended December 31, 2015

Revenues

The following table presents sales, volume and pricing comparisons for the year ended December 31, 2016, as compared to the year ended December 31, 2015:

	Year Ended December 31,									Percentage
	2016			2015			Change			Change
Revenues generated from the sale of frac sand (in thousands)	$	202,709		$	310,466		$	(107,757	)	(35	)%
Tons sold	4,253,746			5,003,702			(749,956		)	(15	)%
Percentage of volumes sold FOB plant	46		%	49		%	(3		)%	(6	)%
Percentage of volumes sold in-basin via our terminal network	53		%	51		%	2		%	4	%
Percentage of volumes sold at the wellsite	1		%	—		%	1		%	—	%
Average price per ton sold	$	48		$	62		$	(14	)	(23	)%

Revenues generated from the sale of frac sand were $202,709 and $310,466 for the years ended December 31, 2016 and 2015, respectively, during which we sold 4,253,746 and 5,003,702 tons of frac sand, respectively. Average sales price per ton was $48 and $62 for the years ended December 31, 2016 and 2015, respectively. The average sales price between the two periods differs due to changes in industry sales price trends, partially offset by the mix in pricing of volumes sold FOB plant and in-basin via our terminal network. With oil and gas prices persisting at levels well below those experienced in the middle of 2014 and the resulting decline in drilling activity, pricing of frac sand continued to decline during 2015 and through the middle of 2016, and we continued to provide additional discounted pricing for contract customers during 2016, as compared to pricing levels in 2015.

Other revenues related to transload and terminaling, railcar storage, silo storage, contract make-wholes and other services was $1,721 and $29,174 for the years ended December 31, 2016 and 2015, respectively. Other revenue in 2015 included $10,190 of make-whole payments related to a contract settlement payment. The decrease in other revenue, excluding the impact of make-whole payments, was driven by decreased transloading and logistics services provided at our terminals, resulting from lower overall industry sand demand and the decrease in volumes sold FOB plant.

Costs of Goods Sold – Production Costs

We incurred production costs of $54,187 and $76,996 for the years ended December 31, 2016 and 2015, respectively. The decrease in production costs was due to a percentage of volumes being produced at our higher cost facilities, offset by an increase in tons produced and delivered during 2015, as compared to 2016. During the year ended December 31, 2016, our production facilities were able to supply all of our sand requirements and as a result we did not purchase any sand from third parties. For the year ended December 31, 2015, we purchased $3,841 of sand from other suppliers.

Costs of Goods Sold – Logistics Costs

We incurred logistics costs of $134,121 and $162,629 for the years ended December 31, 2016 and 2015, respectively, reflecting a decrease in volumes sold in-basin via our terminal network, utilization of silo storage at our terminals and decreases in freight rates and lease costs, which were offset by increased costs of storage of idled rail cars and costs incurred in removing cars from storage.

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

For the years ended December 31, 2016 and 2015, we incurred $17,032 and $16,613, respectively, of depreciation, depletion and amortization expense. The increase was driven by an increased asset base resulting from the completion of our Blair facility, offset by reduced amortization of intangible assets due to the impairment of the Sand Supply Agreement in the third quarter of 2015.

Gross Profit (Loss)

Gross loss was $(910) for the year ended December 31, 2016, compared to gross profit of $83,402 for the year ended December 31, 2015. Gross profit (loss) percentage declined to (0.4)% for the year ended December 31, 2016 from 24.6% for the year ended December 31, 2015. The decline was primarily driven by pricing discounts, decreased volumes, lower asset utilization rates and reduced other revenues.

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Operating Costs and Expenses

For the years ended December 31, 2016 and 2015, we incurred total operating costs and expenses of $69,956 and $41,554, respectively. For the years ended December 31, 2016 and 2015, we incurred general and administrative expenses of $35,501 and $27,811, respectively. The increase in general and administrative expenses was primarily attributable to $850 in transaction costs associated with the Blair Contribution, $407 in other business development costs and $8,236 of bad debt expense associated primarily with a spot customer filing for bankruptcy.

For the year ended December 31, 2016, we incurred impairments and other expenses of $34,025 primarily related to the impairment of goodwill. For the year ended December 31, 2015, we incurred impairments and other expenses of $25,659 related to the impairment of the Sand Supply Agreement, idled administrative and transload facilities, costs associated with staffing reductions and relocations and the write-off of costs associated with abandoned construction projects.

In December 2015, we received a settlement payment of $22,500 for past and future obligations under a customer contract, $12,310 of this settlement was recognized as other operating income, with the remainder of the payment recorded as other revenue for make-whole payments as described above.

Interest Expense

Interest expense was $13,653 and $14,126 for the years ended December 31, 2016 and 2015, respectively. The decrease in interest expense was generally driven by the payment in full of the outstanding balance on our revolver in the second quarter of 2016.

Net Income (Loss)

Net loss was $(84,519) for the year ended December 31, 2016, compared to net income of $27,722 for the year ended December 31, 2015.

Liquidity and Capital Resources

Overview

We expect our principal sources of liquidity will be cash generated by our operations, supplemented by borrowings under our Revolving Credit Agreement, 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 15, 2018, our sources of liquidity consisted of $14,839 of available cash and $104,334 pursuant to available borrowings under our Revolving Credit Agreement ($125,000, net of $20,666 letter of credit commitments) and had no indebtedness. 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.

Revolving Credit Agreement and Term Loan Credit Facility

As of February 15, 2018, we have a $125,000 senior secured Revolving Credit Agreement, which matures in December 2022. As of February 15, 2018, we had $104,334 of undrawn borrowing capacity ($125,000, net of $20,666 letter of credit commitments) and had no indebtedness under our Revolving Credit Agreement. The Revolving Credit Agreement 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. The Revolving Credit Agreement requires compliance with customary financial covenants, which are a maximum leverage ratio of 3.25x, a minimum interest coverage ratio of 2.5x and an asset coverage ratio of 1.5x. The Revolving Credit Agreement generally permits repurchases of common units.

As of December 31, 2017, we are in compliance with the covenants contained in the Revolving Credit Agreement. Our ability to comply with such covenants in the future, and access our undrawn borrowing capacity under our Revolving Credit Agreement, is dependent primarily on achieving certain levels of EBITDA, as defined.

As of February 15, 2018, we have a $200,000 Term Loan Credit Facility, which matures in December 2024. As of February 15, 2018, the Term Loan Credit Facility was fully drawn with a $200,000 balance outstanding. The Term Loan Credit Facility permits us to add one or more incremental term loan facilities in an aggregate amount not to exceed $100,000. Any incremental Term Loan Credit Facility would be on terms to be agreed among us, the administrative agent under the Term Loan Credit Facility and the lenders who agree to participate in the incremental facility.

Borrowings under our Revolving Credit Agreement and Term Loan 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.

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Credit Ratings

As of February 15, 2018, the credit rating of the Partnership’s Term Loan Credit Facility was B3 from Moody’s Investors Service Inc. and B- from Standard and Poor’s.

The credit ratings of the Partnership’s Term Loan Credit Facility 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 15, 2018, the Partnership had not issued any common units under this equity distribution program.

Distributions

On January 17, 2018, our general partner's board of directors declared a cash distribution for the fourth quarter of 2017 of $0.20 per common unit, or $0.80 on an annualized basis, and no distribution was declared for our holders of incentive distribution rights. This distribution was paid on February 13, 2018 to unitholders of record on February 1, 2018. This quarterly distribution equates to approximately $17,809 per quarter, or $71,236 per year, based on the number of common units currently outstanding. We intend to pay a quarterly distribution to the extent we have sufficient operating surplus, as defined in our partnership agreement, and cash generated from our operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates. We do not have a legal or contractual obligation to pay distributions.

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. As of February 15, 2018, the Partnership has repurchased 2,030,163 common units for a total cost of $20,000 under its unit buyback program.

Capital Requirements

During the year ended December 31, 2017, we spent $122,032 related to costs associated with the construction of the Kermit facility, the new terminal facility in Pecos, Texas, equipment for the PropStreamintegrated logistics service and overburden removal, among other projects. We plan to spend $35,000 to $45,000 on capital expenditures in 2018 related to continued investment in equipment for PropStream, normal maintenance capital expenditures, including overburden removal, at our production facilities and terminals, and discretionary investments in logistics assets.

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, divestures or organic capital expenditures. As of December 31, 2017, we had a positive working capital balance of $93,029, as compared to a working capital deficit of $(61,233) at December 31, 2016. The deficit as of December 31, 2016, was driven by $115,961 of cumulative advances received from our sponsor to finance the construction of the Whitehall facility.

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

	Year Ended December 31,
	2017		2016
Current assets:
Accounts receivable, net	$	139,448	$	52,834
Inventories	44,272		29,277
Prepaid expenses and other current assets	2,832		2,716
Total current assets	186,552		84,827
Current liabilities:
Accounts payable	46,794		19,264
Accrued and other current liabilities	29,931		8,155
Current portion of deferred revenues	4,399		—
Due to sponsor	12,399		118,641
Total current liabilities	93,523		146,060
Working capital (deficit)	$	93,029	$	(61,233	)

Accounts receivable increased by $86,614 during the year ended December 31, 2017, reflecting increased volumes sold and improved pricing as compared to the fourth quarter of 2016.

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 $14,995 was primarily driven by wet sand inventory at December 31, 2017 as compared to December 31, 2016 as we had five plants operating at year-end 2017 as compared to three in 2016. In addition, in-basin finished goods inventory increased at December 31, 2017 as compared to December 31, 2016, as we had more on-line production capacity available to forward place product.

Accounts payable and accrued liabilities increased by $49,306 on a combined basis, primarily due to an increase in the outstanding payables associated with increased activity levels at all four Wisconsin production facilities, our Kermit facility, our 12 terminals and our 10 PropStream crews.

Deferred revenues represent prepayments from customers for future deliveries of frac sand. The increase in deferred revenues was due to the receipt of prepayments from customers during the year ended December 31, 2017.

Our balance due to our sponsor decreased $106,242 during the year ended December 31, 2017, primarily as a result of $116,417 of sponsor advances converting to capital on March 15, 2017, in connection with the closing of the Whitehall Contribution.

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

	Year Ended December 31,
	2017			2016			2015
Net cash provided by (used in):
Operating activities	$	96,269		$	(27,985	)	$	100,748
Investing activities	(470,022		)	(127,840		)	(126,526		)
Financing activities	374,894			147,104			33,509

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

Operating Activities

Net cash provided by operating activities was $96,269 for the year ended December 31, 2017, compared to net cash used in operating activities of $27,985 for the year ended December 31, 2016. Operating cash flows include net income of $82,534 and a net loss of $84,519 during the years ended December 31, 2017 and 2016, 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 in 2017 as compared to 2016.

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Investing Activities

Net cash used in investing activities was $470,022 for the year ended December 31, 2017, and consisted of the $140,000 cost of the Whitehall Contribution, the $200,830 cost of the Permian Basin Sand asset acquisition, $7,168 of equity method investments and $122,032 of capital expenditures primarily related to the construction of our Kermit facility and our new terminal facility in Pecos, Texas.

Net cash used in investing activities was $127,840 for the year ended December 31, 2016, and consisted of the $75,000 cost of the Blair Contribution, $10,232 of equity method investments and $44,011 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.

Financing Activities

Net cash provided by financing activities was $374,894 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, $456 of advances received from our sponsor and $438 of proceeds 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, $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 and $5,151 of repayments on other long-term debt.

Net cash provided by financing activities was $147,104 for the year ended December 31, 2016, and was comprised of $189,037 net proceeds from the issuance of 19,550,000 common units, $16,480 of advances received from our sponsor and $111 of proceeds from participants in our unit purchase program, offset by $128 of loan origination costs, a $52,500 repayment of the outstanding balance on our Prior Revolving Credit Agreement and $5,896 of repayments on other long-term debt.

Cash Flows - Year Ended December 31, 2016 Compared to Year Ended December 31, 2015

Operating Activities

Net cash used in operating activities was $27,985 for the year ended December 31, 2016, compared to net cash provided by operating activities of $100,748 for the year ended December 31, 2015. Operating cash flows include a net loss of $84,519 and net income earned of $27,722 during the years ended December 31, 2016 and 2015, respectively, adjusted for non-cash operating expenses and changes in operating assets and liabilities described above. The decrease in cash flows from operations was primarily attributable to decreased gross profit margins, coupled with a net increase in our working capital as compared to 2015.

Investing Activities

Net cash used in investing activities was $127,840 for the year ended December 31, 2016, and consisted of the $75,000 cost of the Blair Contribution, $10,232 of equity method investments and $44,011 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.

Net cash used in investing activities was $126,526 for the year ended December 31, 2015, and consisted of the $127,217 of capital expenditures for the construction of our Blair facility, expansion of our Augusta facility, expansion of silo storage at our terminals in Pennsylvania and Ohio, and construction of our terminal facilities in Colorado and Texas. During the year ended December 31, 2015, $691 of restricted cash was released from escrow upon completion of a project.

Financing Activities

Net cash provided by financing activities was $147,104 for the year ended December 31, 2016, and was comprised of $189,037 net proceeds from the issuance of 19,550,000 common units, $16,480 of advances received from our sponsor and $111 of proceeds from participants in our unit purchase program, offset by $128 of loan origination costs, a $52,500 repayment of the outstanding balance on our Prior Revolving Credit Agreement and $5,896 of repayments on other long-term debt.

Net cash provided by financing activities was $33,509 for the year ended December 31, 2015, and was comprised of $52,500 of net borrowings under the Prior Revolving Credit Agreement, $53,512 of advances from our sponsor and $403 of proceeds from participants in our unit purchase program, offset by $70,072 of distributions to our unitholders, $406 of loan origination costs and $2,428 of repayments of our long-term debt.

Customer Concentration

For the year ended December 31, 2017, sales to each of Halliburton and 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. ("Weatherford") accounted for greater than 10% of our total revenues. For the year ended December 31, 2015, sales to each FTS International Services, LLC, Halliburton, Liberty and Weatherford accounted for greater than 10% of our total revenues.

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Contractual Obligations

The following table presents our contractual obligations and other commitments as of December 31, 2017:

	Total		Less than 1 year		1-3 years		3-5 years		More than 5 years
Repayment of term loan	$	200,000	$	2,000	$	4,000	$	4,000	$	190,000
Estimated interest payments on term loan (a)	73,153		10,775		21,226		20,792		20,360
Repayment of other notes payable	3,054		957		2,097		—		—
Asset retirement obligations (b)	10,179		—		—		—		10,179
Minimum royalty payments	4,800		1,200		1,200		1,200		1,200
Operating lease obligations	157,030		33,787		64,469		42,104		16,670
Minimum purchase commitments (c)	16,946		5,571		4,912		4,592		1,871
Contingent consideration (d)	25,000		25,000		—		—		—
Total contractual obligations	$	490,162	$	79,290	$	97,904	$	72,688	$	240,280

(a) Estimated interest payments on our term loan is calculated using the interest rate in effect at December 31, 2017.

(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.

(d) The Partnership anticipates payment of $5,000 and $20,000 for the 2017 measurement periods related to the Blair Contribution and the Whitehall Contribution, respectively, in March 2018 to our sponsor pending approval from the conflicts committee. Refer to Note 11 - Commitments and Contingencies for additional disclosure regarding the contingent consideration.

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 and Financial Statement Schedules" of this Annual Report for a description of recent accounting pronouncements.

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 and Financial Statement Schedules" of this Annual Report.

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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.  In connection with its recent acquisitions of Blair and Whitehall and Other Assets from its sponsor, the Partnership has entered into certain contingent consideration arrangements.  As such transactions are between entities under common control, any differences between the calculated fair value, and the actual resulting payments in the future will be reflected as an equity adjustment to the deemed distributions associated with the acquisitions.

The Partnership may pay the sponsor up to $10,000 and $65,000 of contingent consideration related to the Blair Contribution and the Whitehall Contribution, respectively.  The payments are based on achievement of certain levels of Adjusted EBITDA in 2017 and 2018.  Achievement of these threshold levels of Adjusted EBITDA, as defined in each of the contribution agreements, will be dependent on the quantity of volumes sold and related prices, which are forecasted at levels above current market prices.  The Partnership’s ability to meet such thresholds will be affected by events and circumstances beyond its control.  If market or other economic conditions remain the same or deteriorate, the thresholds may not be met. If the thresholds are not attained during each of the contingency periods, no payment will be owed to the sponsor.

A 10% increase or decrease in the achievement of Adjusted EBITDA versus current forecasts for the measurement periods could result in a range of potential payments under these arrangements which could differ from the current estimated fair value of the liabilities based on our current forecasts.  Based on the significant estimates and assumptions included in our analysis, actual results could differ from these estimates.

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

Frac sand sales revenues are recognized when legal title passes to the customer, which may occur at the production facility, rail origin, terminal or wellsite. At that point, delivery has occurred, evidence of a contractual arrangement exists and collectability is reasonably assured. Amounts received from customers in advance of sand deliveries are recorded as deferred revenue.

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 2018 and 2024. The agreements define, among other commitments, the volume of product that the Partnership must provide, the price that will be charged to the customer, and the volume that the customer must purchase by the end of the defined cure periods, which can range from three months to the end of a contract year.

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

Transportation services revenues are recognized as the services have been completed, meaning the related services have been rendered. At that point, delivery of service has occurred, evidence of a contractual arrangement exists and collectability is reasonably assured.

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Related Party Transactions

Omnibus Agreement:On August 20, 2012, we entered into an omnibus agreement with our general partner and our sponsor. Pursuant to the terms of this agreement, our sponsor will indemnify us and our subsidiaries for certain liabilities over specified periods of time, including but not limited to certain liabilities relating to (a) environmental matters pertaining to the period prior to our IPO and the contribution of the Wyeville assets from our sponsor, provided that such indemnity is capped at $7,500 in aggregate, (b) federal, state and local tax liabilities pertaining to the period prior to our initial public offering and the contribution of the Wyeville assets from our sponsor, (c) inadequate permits or licenses related to the contributed assets, and (d) any losses, costs or damages incurred by us that are attributable to our sponsor’s ownership and operation of such assets prior to our IPO and our sponsor’s contribution of such assets. In addition, we have agreed to indemnify our sponsor from any losses, costs or damages it incurs that are attributable to our ownership and operation of the contributed assets following the closing of the IPO, subject to similar limitations as on our sponsor’s indemnity obligations to us.

Services Agreement: Effective August 16, 2012, our sponsor entered into a services agreement (the "Services Agreement") with our general partner, Hi-Crush Services LLC ("Hi-Crush Services") and the Partnership, pursuant to which Hi-Crush Services provides certain management and administrative services to the Partnership to assist in operating the Partnership’s business. Under the Services Agreement, the Partnership reimburses Hi-Crush Services and its affiliates, on a monthly basis, for the allocable expenses it incurs in its performance under the Services Agreement. These expenses include, among other things, administrative, rent and other expenses for individuals and entities that perform services for the Partnership. Hi-Crush Services and its affiliates will not be liable to the Partnership for its performance of services under the Services Agreement, except for liabilities resulting from gross negligence. During the years ended December 31, 2017, 2016 and 2015, the Partnership incurred $5,521, $4,938 and $5,260, respectively, of management and administrative service expenses from Hi-Crush Services.

Refer to Note 14 - Related Party Transactions of the Notes to Consolidated Financial Statements in Item 15. "Exhibits and Financial Statement Schedules" of this Annual Report for additional information regarding related party transactions.

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

(Dollars in thousands)

Quantitative and Qualitative Disclosure of Market Risks

Market risk is the risk of loss arising from adverse changes in market rates and prices. 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.

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 drilling and 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.

Interest Rate Risk

As of December 31, 2017, we had $200,000 of principal outstanding under our Term Loan Credit Facility, with an effective interest rate of 5.41%. Assuming no change in the amount outstanding, the impact on interest expense of a 10% increase or decrease in the average interest rate would be approximately $1,082 per year.

Credit Risk – Customer Concentration

During the year ended December 31, 2017, 37% of our revenues were earned from two of our customers. Our customers are generally pressure pumping service providers and oil and gas exploration and production companies. 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 are listed under Item 15. "Exhibits and Financial Statement Schedules" and are set forth beginning on page F-1 immediately following the signature pages of this Annual Report.

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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.

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, 2017, 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, 2017, based on those criteria.

The effectiveness of our internal control over financial reporting as of December 31, 2017 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, 2017, 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.

Report of Independent Registered Public Accounting Firm

To the Board of Directors of Hi-Crush GP LLC

and Unitholders 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, 2017, 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, 2017, 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, 2017, of the Partnership and our report dated February 19, 2018, expressed an unqualified opinion on those financial statements.

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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, 2018

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. As a result of owning our general partner, our sponsor has the right to appoint all members of the board of directors of our general partner, including the independent directors. Our unitholders are not entitled to elect our general partner or its directors or otherwise directly participate in our management or operation. Our general partner owes certain duties to our unitholders as well as a fiduciary duty to its owners.

Our general partner has ten 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, 2017, 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

All of the executive officers of our general partner allocate their time between managing our business and affairs and the business and affairs of our sponsor. While the amount of time that our executive officers devote to our business and the business of our sponsor varies in any given year based on a variety of factors, we currently estimate that each of our executive officers spend approximately 75% of their time on the management of our business. Our executive officers devote as much time to the management of our business and affairs as is necessary for the proper conduct of our business and affairs.

Following the IPO on August 16, 2012, neither our general partner nor our sponsor receive any management fee or other compensation in connection with our general partner’s management of our business, but we reimburse our general partner and its affiliates, including our sponsor, for all expenses they incur and payments they make on our behalf. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our partnership agreement provides that our general partner determines in good faith the expenses that are allocable to us.

In evaluating director candidates, our sponsor assesses 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.

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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 appointed for a one-year term and hold office until their successors have been elected or qualified or until the earlier of their death, resignation, removal or disqualification. Executive officers serve at the discretion of the board. There are no family relationships among any of our directors or executive officers. One of our directors and all of our executive officers also serve as executive officers of our sponsor.

Name	Age	Position With Our General Partner
Robert E. Rasmus	60	Chief Executive Officer and Director
Laura C. Fulton	54	Chief Financial Officer
Mark C. Skolos	58	General Counsel and Secretary
William E. Barker	36	Principal Strategy Officer
James M. Whipkey	60	Chairman of the Board
John F. Affleck-Graves	67	Director
Jefferies V. Alston, III	40	Director
Gregory F. Evans	37	Director
John R. Huff	71	Director
John Kevin Poorman	66	Director
Trevor M. Turbidy	50	Director
Graham R. Whaling	63	Director
Joseph C. Winkler III	66	Director

Robert E. Rasmus—Chief Executive Officer and Director. Mr. Rasmus is a co-founder of Hi-Crush Proppants LLC and has 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 National Industrial Sand Association and 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.

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Mark C. Skolos—General Counsel 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. 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.

James M. Whipkey—Chairman of the Board. Mr. Whipkey has a 35 year background in the oil and natural gas industry with broad experience in both technical and financial areas. Mr. Whipkey was named Chairman of the Board of our general partner in November 2015. Mr. Whipkey is a co-founder of Hi-Crush Proppants LLC and served as its Co-Chief Executive Officer from October 2010 to November 2015. Mr. Whipkey served as Co-Chief Executive Officer of our general partner from May 2012 to November 2015, and was appointed to the board of directors of our general partner in May 2012. Mr. Whipkey was a founding member of ROCM in June 2002 and has served as Managing Director since inception. Prior to the founding of ROCM, Mr. Whipkey was an equity analyst covering the exploration and production sector, most recently as a Managing Director at ABN Amro Bank N.V. From 1997 to 2000, Mr. Whipkey was the Chief Financial Officer and Treasurer for NYSE-listed Benton Oil and Gas Company. Prior thereto, Mr. Whipkey worked in a number of investment banking positions managing a wide range of relationships and responsibilities in the energy sector. His various roles included energy derivatives trading at Phibro Energy Inc., investment banking at Kidder, Peabody & Co., and stock analysis at Lehman Brothers Holdings Inc., where he won "All-Star" recognition from the Wall Street Journal in both the E&P and oil service sectors. Mr. Whipkey began his career as a petroleum engineer with Amoco Corporation where he spent five years in operations, drilling and reservoir simulation roles. Mr. Whipkey holds a BS in Petroleum and Natural Gas Engineering from The Pennsylvania State University and an MBA in Finance from the University of Chicago. We believe that Mr. Whipkey’s experience in senior financial management and knowledge of our business serve him well as a member of the board of directors of our general partner.

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.

Jefferies V. Alston, III—Director. Mr. Alston served as Chief Operating Officer of Hi-Crush Proppants LLC from May 2011 until October 2016 and served as Chief Operating Officer of our general partner from May 2012 until October 2016. Mr. Alston was appointed to the board of directors of our general partner in May 2012. Mr. Alston founded Trinity Consulting, LLC ("Trinity") in December 2009, where he designed and managed construction of numerous frac sand processing facilities and became one of the leading consultants in the industry, until dissolving Trinity to join Hi-Crush Proppants LLC. Mr. Alston worked for Alston Equipment Company, Inc. ("Alston Equipment") from February 1999 until he founded Trinity in December 2009. While at Alston Equipment, Mr. Alston was responsible for sales, growth initiatives and customer relations. Mr. Alston attended The University of Southern Mississippi and Southeastern Louisiana University. With his extensive knowledge of the frac sand industry, we believe Mr. Alston brings substantial experience and leadership skills to the board of directors of our general partner.

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Gregory F. Evans—Director. Mr. Evans has served as a director of Hi-Crush Proppants LLC since January 2014 and was appointed to the board of directors of our general partner in February 2014. Mr. Evans currently serves as a Partner of Avista Energy Capital and previously served in various roles at Avista Capital Partners from 2005 to 2017. From 2003 to 2005, Mr. Evans was an Analyst at DLJ Merchant Banking Partners. Prior to joining DLJ Merchant Banking Partners, he was an Analyst in Credit Suisse First Boston’s Investment Banking Department. Mr. Evans holds a BBA in Finance from the University of Texas at Austin. We believe that Mr. Evans brings financial and analytical expertise in the energy sector, including experience as a director of numerous energy-related companies, to the board of directors of our general partner.

John R. Huff—Director. Mr. Huff has served as a director of Hi-Crush Proppants LLC since May 2011 and was appointed to the board of directors of our general partner in May 2012. Mr. Huff has served as Chairman of the board of directors of Oceaneering International, Inc. ("Oceaneering") since 1990 and served as its Chief Executive Officer from 1986 to 2006. Prior to joining Oceaneering, Mr. Huff served as Chairman, President and Chief Executive Officer of Western Oceanic, Inc. from 1972 to 1986. In addition to his service as chairman of the board of directors of Oceaneering, Mr. Huff has served as a member of the board of directors of Suncor Energy, Inc. since 1998. Mr. Huff also served as a member of the board of directors of Rowan Companies, Inc. from April 2006 to May 2009, of KBR, Inc. from April 2007 to April 2014 and of BJ Services Company from 1992 to April 2010. Mr. Huff received a Bachelor’s degree in Civil Engineering from Georgia Tech and attended the Harvard Business School’s Program for Management Development. Mr. Huff is a Registered Professional Engineer in the State of Texas and a member of the National Academy of Engineering, Washington D.C. We believe that Mr. Huff’s substantial knowledge of energy-related businesses, as well as his considerable experience as a director of public companies, has prepared him well to serve on the board of directors of our general partner.

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.

Trevor M. Turbidy—Director. Mr. Turbidy has served as a director of Hi-Crush Proppants LLC since May 2011 and was appointed to the board of directors of our general partner in May 2012. Mr. Turbidy serves as a Partner of Avista Energy Capital and previously served as an energy industry advisor for Avista Capital Partners from 2007 until 2017. Prior to joining Avista Capital Partners, Mr. Turbidy served as Chief Executive Officer of Trico Marine Services ("Trico"), an international provider of marine support vessel services to the offshore oil and gas industry from 2005 to 2007. Prior to that, Mr. Turbidy was Chief Financial Officer of Trico from 2003 to 2005, functioned as the Chief Restructuring Officer during the company’s restructuring and subsequently was promoted to Chief Executive Officer after its successful completion. Prior to his service at Trico, Mr. Turbidy spent more than a decade with Donaldson, Lufkin & Jenrete Inc. ("DLJ") and Credit Suisse First Boston in their investment banking divisions. During his tenure with DLJ and Credit Suisse First Boston, Mr. Turbidy focused on the energy sector, principally offshore and land drilling contractors, seismic service providers, oilfield equipment manufacturers, offshore support vessel providers and exploration and production companies, as well as regional opportunities in the Southwest. Mr. Turbidy previously served as a director of Grey Wolf, Inc., Precision Drilling Corporation and Trico Marine Services Inc., as well as a number of private companies in the energy industry. Mr. Turbidy holds an AB in Economics from Duke University. We believe that Mr. Turbidy’s substantial management-level experience with public and private companies, together with his considerable knowledge of the energy industry as a whole, are of great value to the board of directors of our general partner.

Graham R. Whaling—Director. Mr. Whaling was appointed to the board of directors of our general partner in February 2015 and has a 35 year background in the energy industry. Mr. Whaling serves as a Partner of Avista Energy Capital and previously served as an energy industry advisor for Avista Capital Partners from 2014 to 2017. Prior to joining Avista Capital Partners, Mr. Whaling served as Chief Executive Officer of Parkman Whaling, an oil and gas investment banking advisory firm, which he co-founded in July 2007. Prior to that, Mr. Whaling was chairman and Chief Executive Officer of Laredo Energy, L.P., which he co-founded in 2001. Mr. Whaling has also been a Managing Director at DLJ Merchant Banking Partners, Chairman and Chief Executive Officer of Monterey Resources Inc. and Chief Financial Officer of Santa Fe Energy Resources, Inc. Mr. Whaling holds an M.B.A. from the Wharton School of the University of Pennsylvania and a bachelor’s degree in petroleum engineering from the University of Texas.  We believe that Mr. Whaling’s substantial management-level experience, together with his extensive knowledge of and background in the energy industry, make him particularly well-qualified to serve on the board of directors of our general partner.

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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 is also a member 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. and is a member of its audit committee. 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, 2017, 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.

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.

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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, including our sponsor, 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 2017, 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 except that a Form 4 filed by Mr. Huff with respect to the acquisition of common units representing limited partner interests in the Partnership pursuant to an in-kind distribution was not timely filed.

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. Other than Messrs. Barker and Welsh, who are employed by Hi-Crush Services, a subsidiary of our sponsor, Hi-Crush Proppants LLC, all of our general partner’s named executive officers are employed by our sponsor. Under the Services Agreement, we reimburse Hi-Crush Services, on a monthly basis, for the allocable expenses that it and our sponsor incurs in compensating our general partner’s named executive officers. Please read Item 13, "Certain Relationships and Related Transactions, and Director Independence-Other Transactions with Related Persons" for more information about the Services Agreement.

Other than equity-based incentive grants under our long-term incentive plan, our sponsor as the ultimate employer of our named executive officers has 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 Chief Financial Officer and General Counsel. Although our sponsor has the ultimate responsibility and authority for non-equity based compensation related decisions for our named executive officers, it regularly consults with, receives recommendations from, and obtains the approval of, the board of directors of our general partner with respect to non-equity based compensation related decisions. All compensation decisions for employees of Hi-Crush Services, including those for the individuals who are executive officers of our general partner, are made at the discretion of our Chief Executive Officer, subject to approval by our sponsor and consultation with 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"), are 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 and, where appropriate, the conflicts committee of the board of directors of our general partner.

For the year ended December 31, 2017, 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 and Secretary

• William E. Barker, Principal Strategy Officer

• Joseph M. Welsh, Vice President, Midstream Operations (a)

(a) Mr. Welsh was appointed Vice President, Midstream Operations of our general partner effective July 11, 2017. Effective January 31, 2018, Mr. Welsh is no longer serving as Vice President, Midstream Operations and has transitioned to a strategic role within our commercial team.

Distributions to Our General Partner

Our general partner is directly owned by our sponsor, which is partially-owned by certain of our named executive officers. We pay 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 our partnership agreement. The amount of each quarterly distribution that we pay to our sponsor is based solely on the provisions of our partnership agreement, which agreement specifies the amount of cash we distribute to our sponsor based on the amount of cash that we distribute to our limited partners each quarter. Accordingly, the cash distributions we make to our sponsor bear no relationship to the level or components of compensation of our named executive officers.

Summary of Key 2017 Results

During 2017, we executed upon key opportunities to expand our business and customer base, reduce our logistics costs, and enhance our capital structure while continuing to operate our plants in the most efficient and cost effective manner:

• Completed construction and startup of the Kermit facility ahead of schedule and within budget with shipments commencing during the third quarter of 2017;

• Completed construction and startup of the new strategically located terminal in Pecos, Texas on time and within budget to better serve our customers in the Permian Basin;

• Expanded to ten crews in PropStream to support our growing customer base to move and manage frac sand from the mine to the well;

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• Reopened our Augusta and Whitehall facilities during the third quarter of 2016 and first quarter of 2017, respectively, to meet customer demands;

• Successfully executed strategies which streamlined processes and lowered supply chain operating and labor costs;

• Improved balance sheet position through a public equity offering in the first quarter of 2017 and successfully refinanced a new five-year Revolving Credit Agreement and seven-year Term Loan Credit Facility; and

• Completed a $20 million unit repurchase under our unit buyback program.

We believe these results along with our competitive strengths position us to successfully execute our strategy and achieve our key business objectives.

Summary of 2017 Compensation Actions and Changes

Peer Group Review and Selection

After consulting with members of the board of directors of our general partner and BDO, USA LLP ("BDO"), our executive compensation consulting group, we selected eight peer companies to replace former peer companies merged into or acquired by other entities to establish a 2016 peer group of eighteen companies for competitive compensation benchmarking analysis. BDO prepared 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. Our sponsor and 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 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.

For determining recommendations for 2017 executive pay actions, BDO updated the 2016 peer group data regression using Hi-Crush Partners LP 2017 market cap and EBITDA. BDO also analyzed survey data from published executive compensation surveys at the 25^th, 50^th and 75^th percentile using energy sector cuts representing companies with revenues ranging from $500 million to $1 billion.

Establishment of Total Direct Compensation Value for the Chief Executive Officer

The total direct compensation target approved in 2017 for Mr. Rasmus includes a base pay component which is 22% of the total compensation mix and variable pay components which comprise 78% 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") (60% of value) and time-based phantom limited partner units ("TPUs") (40% of value). Following is a summary of the total direct compensation target established for Mr. Rasmus in 2017:

Name	Base Salary		STI Target		Annual LTI Target		Total Direct Compensation Target
Robert E. Rasmus, Chief Executive Officer	$	600,000	$	600,000	$	1,560,000	$	2,760,000

Base Salary Increases

Base salary increases were approved for each of the named executive officers with increases ranging from 9% to 22% reflective of market competitiveness and to reflect the growth in the company and the corresponding impact to the scope and increased responsibilities of each position.

Short-Term Cash and Long-Term Incentive Targets

No changes were made to the named executive officers' annual cash incentive targets or long-term incentive targets in 2017.

Incremental Equity Awards

In addition to the annual long-term incentive awards approved by the board of directors of our general partner, approval was made for an incremental equity award for the Chief Executive Officer, Chief Financial Officer, General Counsel and Principal Strategy Officer. The awards were made to increase the retention component of their compensation and to recognize specific 2017 achievements: development and start-up of new facilities, completion of successful financial transactions, and development and execution of strategic third party agreements, all of which support key short-term objectives to expand and diversify our business and to strengthen our capital structure. The award for Mr. Barker was also granted as consideration for his execution of an agreement regarding confidentiality, non-solicitation and non-competition. These incremental awards were granted in TPUs with 50% vesting on the second anniversary of the date of grant and 50% vesting on the third anniversary of the date of grant.

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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 other executive officers;

• 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 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 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.

In August 2016, we engaged the services of BDO to assist us with the review of our peer group and the selection of replacements for nine peer companies which had ceased to be publicly traded since the time of our last competitive pay analysis in 2014: Access Midstream Partners. L.P., Atlas Pipeline Partners, L.P., EnLink Midstream Partners, L.P., Markwest Energy Partners, L.P., Regency Energy Partners, LP, Targa Resources Partners LP, Eagle Rock Energy Partners, L.P., Niska Gas Storage Partners LLC (which has since been acquired by Brookfield Infrastructure Group) and PVR Partners, L.P.

In developing a peer group, BDO includes companies whose size, as measured by market capitalization, total assets, and EBITDA, may be substantially greater than the Hi-Crush enterprise 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.

After careful review, eight companies, comprised of energy-focused partnerships or c-corporations directly competing in the proppants business, were selected: Antero Midstream Partners LP, Emerge Energy Services LP, Fairmount Santrol Holdings, Inc., Calumet Specialty Partners LP, Martin Midstream Partners LP, Tallgrass Energy Partners LP, Dominion Midstream Partners, LP, Holly Energy Partners LP, and Western Refining Logistics, LP.

The final group of eighteen peer companies was utilized by BDO to complete a 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 and therefore the work performed by BDO does not create a conflict of interest. The BDO study was based on compensation as reported in the proxy statements, Form 8-K filings and the annual reports on Form 10-K by each company in the peer group.

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The study was comprised of the following peer companies:

Antero Midstream Partners LP	American Midstream Partners, LP
Emerge Energy Services LP	Boardwalk Pipeline Partners, LP
Carbo Ceramics Inc.	Crestwood Equity Partners LP
DCP Midstream Partners, LP	Dominion Midstream Partners, LP
Fairmount Santrol Holdings, Inc.	Genesis Energy, L.P.
Calumet Specialty Partners LP	Holly Energy Partners LP
NuStar Energy L.P.	Western Refining Logistics, LP
Martin Midstream Partners LP	Summit Midstream Partners, LP
Tallgrass Energy Partners LP	U.S. Silica Holdings, Inc.

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.

As previously noted, for determining recommendations for 2017 executive pay actions, BDO updated the 2016 peer group data regression using Hi-Crush Partners LP 2017 market cap and EBITDA.

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 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 2017, the sponsor and the board of directors of our general partner established a base salary of $600,000 for Mr. Rasmus and approved base salary increases for Ms. Fulton and Mr. Skolos of 9% and 22%, respectively. An increase of 13% was approved for Mr. Barker as a result of his promotion to Principal Strategy Officer. The board of directors of our general partner believe these increases in base salary are appropriate based on the analysis of competitive pay for comparable positions in publicly traded energy industry companies with revenues in the $500 million to $1 billion revenue range. The actual base salaries paid by us to our named executive officers during 2017 are set forth in the "Summary Compensation Table."

Named Executive Officer	2017 Annual Base Salary
Robert E. Rasmus, Chief Executive Officer	$	600,000
Laura C. Fulton, Chief Financial Officer	$	365,000
Mark C. Skolos, General Counsel and Secretary	$	335,000
William E. Barker, Principal Strategy Officer	$	260,000
Joseph M. Welsh, Vice President, Midstream Operations	$	260,000

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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.

In October 2016, the board of directors of our general partner established a short-term annual cash incentive target of 100% of base salary for Mr. Rasmus and STI targets of 85% of base salary for Ms. Fulton and Mr. Skolos and 50% of base salary for Mr. Barker. The board of directors of our general partner approved an annual cash incentive target amount of 50% of base salary for Mr. Welsh as Vice President, Midstream Operations, at the time of his employment.

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 our sponsor and the board of directors of our general partner.

Name and Principal Position	2017 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 and Secretary	85% of base salary
William E. Barker, Principal Strategy Officer	50% of base salary
Joseph M. Welsh, Vice President, Midstream Operations	50% 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 2016 and reviewed in 2017 for named executive officers.

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 and Secretary	—	142,375	284,750	569,500
William E. Barker, Principal Strategy Officer	—	65,000	130,000	260,000
Joseph M. Welsh, Vice President, Midstream Operations	—	65,000	130,000	260,000

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 sponsor and 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 sponsor and the board of directors of our general partner consider 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 our sponsor and 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 sponsor and the board of directors of our general partner ultimately determine 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 and the Hi-Crush enterprise, which includes both Hi-Crush Proppants LLC, the owner of our general partner, and its subsidiaries, and the Partnership combined.

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The financial growth objectives for the 2017 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 $89.4 million (weighted 50%);

(2) Resumption of cash distributions to unitholders by November 15, 2017 (weighted 25%), and

(3) Achievement of a targeted year-over-year growth of 15% in total unitholder return (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 sponsor and the board of directors of our general partner before final approval in the December/January timeframe each year.

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 our sponsor and 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.

STI payouts for the Chief Executive Officer and the Chief Financial Officer, are weighted 80% on the Partnership’s financial growth objectives and 20% on the applicable strategic individual and operating objectives. The STI payout for the General Counsel 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 and Mr. Welsh are weighted 40% on the Partnership's financial growth objectives, 30% on the applicable operating objectives for the midstream business segment, and 30% on strategic individual objectives.

The sponsor and the board of directors of our general partner may also subjectively consider the individual leadership, performance and efforts of each officer with respect to the Partnership's achievement of these goals and objectives. Additionally, our sponsor and 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 sponsor and the board of directors of our general partner reviewed the 2017 Partnership results as summarized below:

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Financial Growth Objectives

Adjusted EBITDA in millions
Threshold	Target	Maximum	Actual	Payout Factor
$71.5	$89.4	$107.3	$124.9	200%

Resumption of Cash Distributions to Unitholders
Threshold	Target	Maximum	Actual	Payout Factor
Jan-18	Nov-17	Aug-17	Nov-17	100%

Year-Over-Year Growth in Total Unitholder Return %
Threshold	Target	Maximum	Actual	Payout Factor
10%	15%	20%	(45)%	—%

Performance relative to Adjusted EBITDA and Resumption of Cash Distributions to Unitholders was at Maximum and Target, respectively, yielding a payout factor of 200% and 100%, respectively. Our 2017 Total Unitholder Return performance of (45)% is calculated based on the December 30, 2016 closing unit price of $19.80 and the December 29, 2017 closing unit price of $10.70 and a $0.15 per unit distribution on November 14, 2017, which yields a payout factor of zero. Our total unitholder return for the period of December 31, 2015 through December 31, 2016 was 234%.

Operating Objectives

In addition to our financial results, the sponsor and 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 2017 operating objectives, actual performance ranged between target and maximum levels for safety, regulatory and environmental compliance, plant uptime and operating efficiency goals, midstream freight rate management and control of labor costs. Actual performance was below threshold for achievement of operating costs below planned costs on a per ton basis within midstream operations and below threshold for achievement of operating costs below planned costs on a per ton basis for plant operations as well as other specific logistics cost containment metrics.

Other Strategic Objectives

In addition to reviewing the financial growth and operating performance results, the sponsor and 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 management and the Chief Executive Officer.

Due to the achievement of key 2017 financial growth objectives, achievement of operating objectives above target overall, and execution of many our 2017 strategic goals, the board of directors of our general partner, in discussions with the Chief Executive Officer, exercised discretion to award cash incentive payouts to the named executive officers.

The financial growth metrics and key operating performance indicators utilized in 2017 for operation of the STI were generally the same for 2015 and 2016 STI plan operation. No STI payments were funded for 2015 or 2016 performance, based on financial performance below the established threshold levels for adjusted EBITDA, annual growth in distributions to unitholders, and total unitholder return, notwithstanding operating performance exceeding targets.

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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 2017, the board of directors of our general partner approved a long-term incentive award for Mr. Rasmus equal to 250% of base salary to be granted in both PPUs (60% of value) and TPUs (40% of value). The board also approved long-term incentive awards for each of the other named executive officers of both PPUs (60% of value) and TPUs (40% of value).

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 ("TUR"), over a three-year performance period compared to the TUR of each entity in the Alerian MLP Index based on the Partnership's average position among the Peer Group for each calendar quarter in the performance period based on Quarterly TUR. 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. 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.

If our Average TUR ranking among the companies in the group over the performance period is below the 25th percentile, 0% of the performance units will vest. If our Average TUR ranking over the performance period is greater than the 25th percentile but less than or equal to the 50th percentile, 50% to 100% of the performance units will vest. If our Average TUR ranking over the performance period is greater than the 50th percentile but less than or equal to the 75th percentile, 100% to 200% of the performance units will vest. If our Average TUR ranking over the performance period is greater than the 75th percentile, 200% of the performance units will vest. The number of phantom units that vest between applicable percentiles will be determined by straight-line interpolation. If the TUR for the Partnership during the performance period is negative (i.e. the price on the first trading day of the performance period is greater than the sum of the price on the last trading day of the performance period plus the aggregate distribution amount), then the number of phantom units earned shall not exceed 150% of the target amount. 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%.

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

To determine the number of PPUs or TPUs to be granted to each named executive officer in 2017, 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 of grant. 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 2017 long-term incentive award values granted, expressed as a percentage of base salary and the number of PPUs and TPUs awarded on December 8, 2017 and December 14, 2017, were as follows:

Name and Principal Position	2017 Long-Term Incentive Award Value (a)	2017 PPUs Awarded (b)	2017 TPUs Awarded (c)
Robert E. Rasmus, Chief Executive Officer	250% of base salary	85,714	57,143
Laura C. Fulton, Chief Financial Officer	165% of base salary	34,286	22,857
Mark C. Skolos, General Counsel and Secretary	150% of base salary	28,571	19,048
William E. Barker, Principal Strategy Officer	130% of base salary	19,143	12,762

(a) Award value is delivered 60% in PPUs and 40% in TPUs.

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

(c) Coincident with his employment, Mr. Welsh received 42,168 TPUs under the LTIP on August 1, 2017, which vest 50% on August 1, 2019 and the remainder vesting on August 1, 2020, assuming continuous employment over the service period.

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Enhancement to 2016 Long-Term Incentive Awards

In addition to the annual long-term incentive award value, an incremental equity award for each named executive officer was approved by the board of directors of our general partner to increase retention value and to recognize specific achievements related to the development and start-up of new service offerings and facilities, completion of successful financial transactions, and development and execution of strategic third party agreements, all of which support key short-term objectives to expand and diversify our business and to strengthen our capital structure. The award for Mr. Barker was also granted as consideration for his execution of an agreement regarding confidentiality, non-solicitation and non-competition. These awards were approved in December 2017, in TPUs as follows:

Name and Principal Position	2017 Incremental Value		2017 TPUs Awarded
Robert E. Rasmus, Chief Executive Officer	$	350,000	33,333
Laura C. Fulton, Chief Financial Officer	$	250,000	23,810
Mark C. Skolos, General Counsel and Secretary	$	250,000	23,810
William E. Barker, Principal Strategy Officer	$	150,000	14,286

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

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, each named executive officer participating in the Second 2017 UPP was granted the right to purchase, on November 15, 2018 at $7.82 per common unit, up to the number of common units set forth in the table below, which shall be equal to (i) such named executive officer’s elected percentage of compensation multiplied by (ii) his or her actual eligible compensation during the period of the Second 2017 UPP's applicability divided by (iii) $7.82, in each case capped at 30,000 common units:

Name and Principal Position	Purchase Rights for Common Units Granted Under the Second 2017 UPP (a)
Robert E. Rasmus, Chief Executive Officer	30,000
Laura C. Fulton, Chief Financial Officer	30,000
Mark C. Skolos, General Counsel and Secretary	2,382
William E. Barker, Principal Strategy Officer	12,367
Joseph M. Welsh, Vice President, Midstream Operations	7,672

(a) Calculated based on the application of the formula set forth above, using the named executive officer’s current elected percentage of compensation and current amount of eligible compensation.

Incentive Profits Interests

Pursuant to their employment agreements, each of Ms. Fulton and Mr. Skolos have been granted a 0.75% profits interest and 0.25% profits interest, respectively, in our sponsor entitling them to receive 0.75% and 0.25%, respectively, of any net distributions by our sponsor after the capital members of the sponsor have received aggregate distributions from our sponsor above applicable threshold amounts for each executive officer. No profits interest was paid to Ms. Fulton or Mr. Skolos in 2017.

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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, 2017, 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 $10,800. 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 unit options for equity awards 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.

Tax and Accounting Implications of Equity-Based Compensation Arrangements

Deductibility of Executive Compensation

We are a partnership and not a corporation for U.S. federal income tax purposes. Therefore, we believe that the compensation paid to our named executive officers is not subject to the deduction limitations under Section 162(m) of the Internal Revenue Code and therefore is generally fully deductible for federal income tax purposes.

Accounting for Unit-Based Compensation

For unit-based compensation arrangements, including equity-based awards issued to our named executive officers, we record compensation expense over the vesting period of the awards, as discussed further in Note 13 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 USA, LLP, an executive compensation consulting firm, to conduct a study in 2016 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, 2017.

Board of Directors

John F. Affleck-Graves

Jefferies V. Alston, III

Gregory F. Evans

John R. Huff

John Kevin Poorman

Robert E. Rasmus

Trevor M. Turbidy

R. Graham Whaling

James M. Whipkey

Joseph C. Winkler III

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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.

Compensation Tables

Summary Compensation Table

The following table shows the compensation paid or otherwise awarded to our fiscal year 2017 named executive officers for services rendered to us and our subsidiaries during fiscal years 2017, 2016 and 2015, as applicable.

Name and Principal Position	Year	Salary ($)(a)	Equity Awards ($)(b)	Non-Equity Incentive Plan Compensation ($)(a)(c)	All Other Compensation ($)(d)		Total $
Robert E. Rasmus Chief Executive Officer	2017	—	1,607,996	—	49,759	(e)	1,657,755
	2016	—	2,137,882	—	44,063	(e)	2,181,945
	2015	1	—	—	39,247	(e)	39,248
Laura C. Fulton Chief Financial Officer	2017	316,058	668,062	332,500	27,397	(f)	1,344,017
	2016	247,500	887,346	—	18,062		1,152,908
	2015	225,000	412,720	—	16,830		654,550
Mark C. Skolos General Counsel and Secretary	2017	209,712	594,577	251,250	29,800		1,085,339
	2016	206,250	723,735	—	26,280	(f)	956,265
	2015	187,500	300,160	—	15,443		503,103
William E. Barker Principal Strategy Officer	2017	220,692	382,468	166,250	15,615	(f)	785,025
	2016	172,500	426,058	—	10,848		609,406
	2015	102,500	193,347	—	7,759		303,606
Joseph M. Welsh Vice President, Midstream Operations	2017	119,000	314,995	—	12,084		446,079

(a) The cash compensation paid or awarded by us reflects only the portion of our sponsor’s or Hi-Crush Services’ compensation expense allocated to us by Hi-Crush Services under the Services Agreement. The percentage of cash compensation expense allocated to us for each named executive officer is as follows: Mr. Rasmus, 0%; Ms. Fulton, 95%; Mr. Skolos, 75%; Mr. Barker, 95%; and Mr. Welsh, 100%.

(b) 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 13 to our consolidated financial statements for additional assumptions underlying the value of the equity awards.

(c) 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.

(d) Amounts in this column reflect the amount paid by our sponsor since 2015 that was reimbursable by us under the Services Agreement for matching 401(k) contributions and premiums paid for health and welfare benefits and coverage.

(e) Pursuant to a management services agreement entered into between Red Oak Capital Management LLC and our sponsor, our sponsor reimburses Red Oak Capital Management LLC for the health and welfare benefits and coverage paid for Mr. Rasmus.

(f) Amount includes value for health and welfare benefits and coverage and value of car allowance provided to Mr. Skolos, values for matching 401(k) contributions and premiums paid for health and welfare benefits and coverage for Ms. Fulton, and value for health and welfare benefits and coverage for Mr. Barker.

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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 2017 to our named executive officers.  The table includes awards made during or for 2017.  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 2017.  Amounts actually paid under that plan for 2017 that were allocated to us by Hi-Crush Services under the Services Agreement are set forth in the Summary Compensation Table under the caption "Non-Equity Incentive Plan Compensation."

		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 2017 PPU	12/14/2017	—	—	—	42,857	85,714	171,428	630,855
December 2017 TPU	12/14/2017	—	—	—	—	90,476	—	977,141
Laura C. Fulton
Short-term incentive plan	N/A	155,125	310,250	620,500	—	—	—	—
December 2017 PPU	12/8/2017	—	—	—	17,143	34,286	68,572	222,859
December 2017 TPU	12/8/2017	—	—	—	—	46,667	—	445,203
Mark C. Skolos
Short-term incentive plan	N/A	142,375	284,750	569,500	—	—	—	—
December 2017 PPU	12/8/2017	—	—	—	14,286	28,571	57,142	185,712
December 2017 TPU	12/8/2017	—	—	—	—	42,858	—	408,865
William E. Barker
Short-term incentive plan	N/A	65,000	130,000	260,000	—	—	—	—
December 2017 PPU	12/8/2017	—	—	—	9,572	19,143	38,286	124,430
December 2017 TPU	12/8/2017	—	—	—	—	27,048	—	258,038
Joseph M. Welsh
Short-term incentive plan	N/A	65,000	130,000	260,000	—	—	—	—
August 2017 TPU	8/1/2017	—	—	—	—	42,168	—	314,995

(a) Amounts shown represent amounts under the STI. If minimum levels of performance are not met, 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 8, 2017 and December 14, 2017 will vest in their entirety after December 31, 2019 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 13 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, 2017:

	Outstanding LTIP Awards
Name and Principal Position	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, Chief Executive Officer	344,585	3,687,060
Laura C. Fulton, Chief Financial Officer	155,975	1,668,933
Mark C. Skolos, General Counsel and Secretary	131,607	1,408,195
William E. Barker, Principal Strategy Officer	82,002	877,421
Joseph M. Welsh, Vice President, Midstream Operations	42,168	451,198

(a) PPUs were awarded in February 2015, September 2016 and December 2017 and vest in their entirety over a range of 0% to 200% within 45 days after December 31, 2017, 2018 and 2019, respectively, if and to the extent to which, 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 2015, 2016 and 2017 PPUs. Our Average TUR ranking over the performance period for the 2015 PPUs approximated the 46th percentile. Therefore 90% of the target performance units vested on February 13, 2018, as determined by the board of directors of our general partner. Additionally, Mr. Barker was granted TPUs in February 2015 which vested 100% in February 2018. TPUs were awarded in September 2016 and December 2017 to all then-employed named executive officers other than Mr. Welsh 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, 2017 of our common units at $10.70.

Option Exercises and Units Vested

The following table provides information regarding units vesting for named executive officers during the year ended December 31, 2017:

	Unit Awards
Name	Number of Units  Acquired on Vesting	Value Realized on Vesting ($)(a)
William E. Barker	1,024	13,517

(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.

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, 2017. 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 2017 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."

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Name and Principal Position	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, Chief Executive Officer	3,687,060	750,000	—	—
Laura C. Fulton, Chief Financial Officer	1,668,933	182,500	—	182,500
Mark C. Skolos, General Counsel and Secretary	1,408,195	167,500	—	167,500
William E. Barker, Principal Strategy Officer	877,421	—	—	—
Joseph M. Welsh, Vice President, Midstream Operations	451,198	—	—	—

Employment Agreements. Other than Mr. Barker and Mr. Welsh, each of our named executive officers has entered into an employment agreement with our sponsor. 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 our sponsor 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 our sponsor 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 our sponsor’s salary payment practices.

Upon a termination by our sponsor 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 and (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 our sponsor’s salary payment practices. Payment of the additional lump sum payment is 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.

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 our sponsor, (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, as determined by a majority of our sponsor’s board of directors.

• Good Reason means, without the named executive officer’s consent: (i) a material breach by our sponsor 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.

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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, 2017.

Name and Principal Position	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, Chief Executive Officer	750,000	—	—
Laura C. Fulton, Chief Financial Officer	182,500	—	182,500
Mark C. Skolos, General Counsel and Secretary	167,500	—	167,500
William E. Barker, Principal Strategy Officer	—	—	—
Joseph M. Welsh, Vice President, Midstream Operations	—	—	—

Performance Phantom Unit Grants under the LTIP. Each of our named executive officers held PPUs, under our form of phantom unit award agreement (the "PPU Award Agreement") and the LTIP as of December 31, 2017. 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. The Average TUR for the Partnership and for each entity in the Peer Group shall be determined for each such shortened performance period and the target amount of phantom units to be received by participant shall be calculated in accordance with performance conditions previously stated.

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;

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, 2017. The amounts reported below assume that the price per unit of our common units was $10.70, which was the closing price per unit of our common stock on December 31, 2017.

Name and Principal Position	Change in Control ($) (a)
Robert E. Rasmus, Chief Executive Officer	3,687,060
Laura C. Fulton, Chief Financial Officer	1,668,933
Mark C. Skolos, General Counsel and Secretary	1,408,195
William E. Barker, Principal Strategy Officer	877,421
Joseph M. Welsh, Vice President, Midstream Operations	451,198

(a) Amounts reported relate to the PPUs awarded in September 2016 and December 2017, which vest in their entirety over a range of 0% to 200% within 45 days after December 31, 2018 and 2019, 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 and December 2017 that are expected to vest is based on assumed performance of 100%. The amounts also include the value of the TPUs which were granted in February 2015, September 2016, August 2017 and December 2017.

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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 employees of our sponsor and its wholly owned subsidiaries who conduct our business and the annual total compensation of Robert E. Rasmus, the Chief Executive Officer of our general partner ("CEO"). Our independent compensation consultants assisted us in the calculation of this ratio.

For 2017, our last completed fiscal year:

• The median of the annual total compensation of all employees (other than the CEO) was $78,532; 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 $1,657,755.

• Based on this information, for 2017 the ratio of the annual total compensation of the CEO to the median of the annual total compensation of all employees other than the CEO ("CEO Pay Ratio") was reasonably estimated to be 21 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, 2017, our employee population consisted of 601 individuals. This population consisted of our full-time, part-time, and temporary employees of our sponsor and its wholly owned subsidiaries.

• We used a consistently applied compensation measure to identify our median employee of comparing the amount of gross earnings paid in 2017. We identified our median employee by consistently applying this compensation measure to all employees included in our analysis. For individuals hired after January 1, 2017 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 2017 year in accordance with the requirements of Item 402(c)(2)(x) of Regulation S-K, resulting in annual total compensation of $78,532. With respect to the annual total compensation of our CEO, we used the amount reported in the "Total" column of our 2017 Summary Compensation Table included in this Annual Report on Form 10-K.

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 table below sets forth the annual compensation earned during 2017 by the non-executive directors of our general partner.

Director	Fees Earned or Paid in Cash ($) (a)	Unit Awards ($)	All Other Compensation ($)		Total ($)
John F. Affleck-Graves	—	120,000	—		120,000
Jefferies V. Alston, III	—	—	25,000	(b)	25,000
Gregory F. Evans	—	—	—		—
John R. Huff	—	100,000	—		100,000
John Kevin Poorman	—	120,000	—		120,000
Trevor M. Turbidy	—	—	—		—
R. Graham Whaling	—	—	—		—
James M. Whipkey	—	—	—		—
Joseph C. Winkler III	—	150,000	—		150,000

(a) Similar to 2017, in 2018, each independent director and Mr. Huff will receive 100% of their annual retainer and grant, as outlined below, in partnership units.

(b) Represents amounts earned in 2017 under Mr. Alston's Separation and Consulting Agreement with the Partnership, the general partner and the sponsor. An additional amount of $6,250 was earned in 2016 but paid in 2017 to Mr. Alston under his Separation and Consulting Agreement.

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Following the IPO on August 16, 2012, each independent director of our general partner has received an annual retainer of $50,000. In 2017, the directors received this retainer in units. Each January, our independent directors have also received an annual grant of the number of common units having a grant date fair value of approximately $50,000 as of such date. Such units are not subject to a vesting period. Further, each independent director serving as a chairman or a member of a committee of the board of directors of our general partner has received an annual retainer of $25,000 or $10,000, respectively. Beginning in 2014, Mr. Huff, who is not an independent director, also received the foregoing annual retainers and grants.

As discussed in Item 11, "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, up to the number of common units set forth in the table below, which shall be equal to such director’s aggregate dollar amount of contributions elected to be made to the Second 2017 UPP during the period of the Second 2017 UPP’s applicability divided by $7.82, capped at 30,000 common units:

Director (a)	Purchase Rights for Common Units Granted Under the Second 2017 UPP (b)
John F. Affleck-Graves	25,575
John R. Huff	28,772
Joseph C. Winkler III	28,772

(a) The Second 2017 UPP participation of directors who are named executive officers is provided in Item 11, "Compensation Discussion and Analysis-Components of Executive Compensation-Other Compensation-Unit Purchase Program" above.

(b) Calculated based on application of the formula set forth above, using the dollar amount of contributions currently elected by the director.  This number may be reduced based on reductions in the director’s elected dollar amount of contributions.

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 2017. 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.

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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 15, 2018 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.

Name of Beneficial Owner (a)	Common Units Beneficially Owned	Percentage of Common Units Beneficially Owned
Hi-Crush GP LLC	—	—	%
Robert E. Rasmus (b)	2,745,614	3.1	%
Jefferies V. Alston, III	2,639,250	3.0	%
Laura C. Fulton	230,673	*
Mark C. Skolos	76,444	*
William E. Barker	20,892	*
James M. Whipkey	2,659,350	3.0	%
John F. Affleck-Graves	67,015	*
Gregory F. Evans	44,860	*
John R. Huff	623,270	*
John Kevin Poorman	44,254	*
Trevor M. Turbidy	68,910	*
Joseph M. Welsh	40	*
R. Graham Whaling	29,694	*
Joseph C. Winkler III	77,498	*
All executive officers and directors as a group (14 persons)	9,327,764	10.5	%

*  Less than one percent

(a) The address for each of Hi-Crush GP LLC, Robert E. Rasmus, Jefferies V. Alston, III, Laura C. Fulton, Mark C. Skolos, William E. Barker, James M. Whipkey, John R. Huff, John F. Affleck-Graves, Joseph M. Welsh, Joseph C. Winkler III and John Kevin Poorman is 1330 Post Oak Blvd, Suite 600, Houston, Texas 77056. The address for each of Gregory F. Evans, Trevor M. Turbidy and R. Graham Whaling is 1000 Louisiana St., Suite 3700, Houston, Texas 77002.

(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.

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Equity Compensation Plan Information

The following table sets forth information as of December 31, 2017 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)	1,729,733	(b)	—		2,193,681
Total for equity compensation plans	1,729,733		$	—	2,193,681

(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 First Amended and Restated Long-Term Incentive Plan (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 phantom units subject to equity-settled time-based unit awards ("TPUs") and performance unit awards ("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 692,282 units being potentially issuable under the LTIP. There is no exercise price applicable to these awards. Also includes the purchase rights for units granted under the Second 2017 Unit Purchase Program, which is approximately 347,000 common units as of December 31, 2017 based on all participants' elected percentage of compensation or aggregate dollar contribution, as applicable, through such date. These purchase rights are expected to be exercised on November 15, 2018 at $7.82 per common unit for those participants eligible on September 11, 2018.

(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.

On January 31, 2018, the Partnership issued 36,109 common units to certain directors. Any units awarded after December 31, 2017 are not included in the Equity Compensation Plan Information table above, which provides information as of December 31, 2017.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

(Dollars in thousands)

As of February 15, 2018, our sponsor owned the incentive distribution rights and owned and controlled our general partner. Our sponsor also appoints all of the directors of our general partner, which maintains a non-economic general partner interest in us.

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.

Distributions and Payments to Affiliates of our General Partner

The following summarizes the distributions and payments made or to be made by us to our general partner and its affiliates in connection with the formation, ongoing operation and any liquidation of Hi-Crush Partners LP.

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Formation Stage

The aggregate consideration received by affiliates of our general partner for the contribution of their interests:

• 13,640,351 common units including 12,937,500 common units Hi-Crush Proppants LLC, as the selling unitholder, sold to the public in our IPO;

• 13,640,351 subordinated units; and

• our incentive distribution rights.

Operational Stage

Distributions of cash available for distribution to our general partner and its affiliates:

• We will generally make cash distributions to our unitholders. In addition, if distributions exceed $0.54625 per unit and other higher target distribution levels, our sponsor (as the holder of our incentive distribution rights) will be entitled to increasing percentages of the distributions, up to 50.0% of the distributions above the highest target distribution level.

Payments to our general partner and its affiliates:

• Our general partner does not receive a management fee or other compensation for its management of our partnership, but we reimburse our general partner and its affiliates for all direct and indirect expenses they incur and payments they make on our behalf. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us.

Withdrawal or removal of our general partner:

• If our general partner withdraws or is removed, its non-economic general partner interest and our sponsor’s incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests.

Liquidation Stage

• Upon our liquidation, the partners will be entitled to receive liquidating distributions according to their particular capital account balances.

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 addresses 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.

The omnibus agreement can be amended by written agreement of all parties to the agreement. However, we may not agree to any amendment or modification that would, in the reasonable discretion of our general partner, be adverse in any material respect to the holders of our common units without prior approval of the conflicts committee. So long as our sponsor controls our general partner, the omnibus agreement will remain in full force and effect unless mutually terminated by the parties. If our sponsor ceases to control our general partner, the omnibus agreement will terminate.

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Registration Rights Agreement

In connection with our IPO on August 16, 2012, we entered into a registration rights agreement with our sponsor (the "Registration Rights Agreement"), pursuant to which we may be required to register the sale of 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") it holds. Under the Registration Rights Agreement, our sponsor will have the right to request that we register the sale of Registrable Securities held by it, and our sponsor will have 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 will be entitled to these registration rights.

Services Agreements

Effective August 16, 2012, our sponsor entered into a services agreement (the "Services Agreement") with our general partner, Hi-Crush Services LLC ("Hi-Crush Services") and the Partnership, pursuant to which Hi-Crush Services provides certain management and administrative services to the Partnership to assist in operating the Partnership’s business. Under the Services Agreement, the Partnership reimburses Hi-Crush Services and its affiliates, on a monthly basis, for the allocable expenses it incurs in its performance under the Services Agreement. These expenses include, among other things, administrative, rent and other expenses for individuals and entities that perform services for the Partnership. Hi-Crush Services and its affiliates will not be liable to the Partnership for its performance of services under the Services Agreement, except for liabilities resulting from gross negligence. During the years ended December 31, 2017, 2016 and 2015, the Partnership incurred $5,521, $4,938 and $5,260, respectively, of management and administrative service expenses from Hi-Crush Services.

Agreements with Affiliates in connection with our Acquisition of Hi-Crush Whitehall LLC, the remaining 2.0% equity interest in Hi-Crush Augusta LLC, and all of the outstanding membership interests in PDQ Properties LLC

On February 23, 2017, the Partnership entered into a contribution agreement with our sponsor to acquire all of the outstanding membership interests in Hi-Crush Whitehall LLC, the entity that owned our sponsor’s Whitehall facility, the remaining 2.0% equity interest in Hi-Crush Augusta LLC, and all of the outstanding membership interests in PDQ Properties LLC, for $140,000 in cash and up to $65,000 of contingent consideration over a two-year period (the "Whitehall Contribution"). The Partnership completed this acquisition on March 15, 2017. The Partnership anticipates payment of $20,000 of contingent consideration with respect to the 2017 measurement period in March 2018 to our sponsor pending approval from the conflicts committee.

Other Transactions with Related Persons

In the normal course of business, our sponsor and its affiliates, including Hi-Crush Services, and the Partnership may from time to time make payments on behalf of each other.

As of December 31, 2017 and 2016, an outstanding balance of $12,399 and $118,641, respectively, payable to our sponsor is maintained as a current liability under the caption "Due to sponsor". On March 15, 2017 and August 31, 2016, $116,417 and $120,950, respectively, of sponsor advances were converted into capital. The December 31, 2016 balance was primarily related to construction advances made to Whitehall.

During the year ended December 31, 2015, the Partnership purchased $2,754 of sand from Goose Landing, LLC, a wholly owned subsidiary of Northern Frac Proppants II, LLC, which is reflected in cost of goods sold. During the years ended December 31, 2017 and 2016, the Partnership did not purchase any sand from Goose Landing, LLC. The father of Mr. Alston, who is a director of our general partner, owned a beneficial equity interest in Northern Frac Proppants II, LLC.

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. As of December 31, 2017 and 2016, the Partnership purchased $6,593 and $1,566, respectively, of equipment from PropX, which is reflected in property, plant and equipment. As of December 31, 2017 and 2016, the Partnership had accounts payable of $1,273 and $1,553, 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, 2017 and 2016, we incurred $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, 2017, 2016 and 2015, 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 is 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.

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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. Such a conflict of interest may arise, for example, in connection with negotiating and approving the acquisition of any assets from our sponsor. 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, including our sponsor, by our unitholders.

We expect to have the opportunity to acquire additional assets from our sponsor in the future. Our sponsor or other affiliates of our general partner are free to offer properties to us on terms they deem acceptable. Under our code of business conduct and ethics, the board of directors of our general partner (or the conflicts committee, if the board of directors delegates the necessary authority to the conflicts committee) will be free to accept or reject any such offers and to negotiate any terms it deems acceptable to us and that the board of directors of our general partner or the conflicts committee will decide the appropriate value of any assets offered to us by affiliates of our general partner. In making such determination of value, the board of directors of our general partner or the conflicts committee are permitted to consider any factors they determine in good faith to consider. The board of directors of our general partner or the conflicts committee will consider a number of factors in its determination of value, including, without limitation, operating data, reserve information, operating cost structure, current and projected cash flow, financing costs, the anticipated impact on distributions to our unitholders, the price outlook for frac sand, reserve life and the location and quality of the reserves.

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 year ended December 31, 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 year ended December 31, 2017 were pre-approved by our sponsor or the board of directors of our general partner, as applicable.

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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. PwC's reports on the Partnership’s consolidated financial statements as of and for the fiscal year ended December 31, 2016 did not contain any adverse opinion or a disclaimer of opinion, nor were they qualified or modified as to uncertainty, audit scope or accounting principles. During the Partnership’s fiscal year ended December 31, 2016 and the subsequent interim period through March 28, 2017, (i) the Partnership has not had any disagreements with PwC on any matter of accounting principles or practices, financial statement disclosure or auditing scope or procedures, which disagreements, if not resolved to PwC's satisfaction, would have caused PwC to make reference to the subject matter of the disagreements in their reports on the Partnership’s consolidated financial statements for such fiscal years, and (ii) there were no "reportable events" as that term is defined in Item 304(a)(1)(v) of Regulation S-K. All PwC services and fees in the year ended December 31, 2016 and the subsequent interim period through March 28, 2017 were pre-approved by our sponsor or the board of directors of our general partner, as applicable.

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 year ended December 31, 2017 and the aggregate fees billed by PwC for professional audit services and other services rendered to the Partnership during the year ended December 31, 2016 and the subsequent interim period in 2017 before the change in auditors became effective:

	Year Ended December 31,
	2017				2016
(in thousands)	Deloitte		PwC		PwC
Audit Fees	$	520	$	—	$	890
All Other Fees (a)	—		135		—
Audit-Related Fees (b)	—		238		174
Tax Fees (c)	—		369		539
Total Fees paid	$	520	$	742	$	1,603

(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 2017 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 2017, 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 are set forth beginning on page F-1 immediately following the signature pages of this Annual Report.

(a)(2) Financial Statement Schedules

Schedule II - Valuation and Qualifying Accounts

Schedule II is filed as part of this Annual Report 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).
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	Second Amended and Restated Agreement of Limited Partnership of Hi-Crush Partners LP, dated January 31, 2013 (incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K, filed with the SEC on February 5, 2013; 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	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).
10.1	Second Amended and Restated Credit Agreement, dated December 22, 2017, among Hi-Crush Partners LP, as borrower, ZB, N.A. dba Amegy Bank, as administrative agent, issuing lender and swing line lender, IBERIABANK, as syndication agent, and the lenders named therein (incorporated by reference to Exhibit 10.2 of the Registrant’s Current Report on Form 8-K, filed with the SEC on December 27, 2017; File No. 001-35630).
10.2	Amended and Restated Credit Agreement, dated December 22, 2017, by and among Hi-Crush Partners LP, as borrower, Morgan Stanley Senior Funding, Inc., as administrative agent and collateral agent, and the lenders named therein (incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K, filed with the SEC on December 27, 2017; 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).

97

Exhibit  Number	Description
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†	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).
10.13†	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).
10.14†	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).
10.15†	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).
10.16†	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).
10.17†	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).
10.18†	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).
10.19†	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).
10.20†	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).
16.1	Letter to Securities and Exchange Commission from PricewaterhouseCoopers LLP, dated March 30, 2017 (incorporated by reference to Exhibit 16.1 of the Registrant’s Current Report on Form 8-K, filed with the SEC on March 31, 2017; File No. 001-35630).
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

98

Exhibit  Number	Description
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.

99

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 20, 2018.

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 20, 2018.

Hi-Crush Partners LP (Registrant)

By: Hi-Crush GP LLC, its general partner

Name	Capacity
/s/ Robert E. Rasmus	Chief Executive Officer and Director (Principal Executive Officer)
Robert E. Rasmus
/s/ Laura C. Fulton	Chief Financial Officer (Principal Financial and Accounting Officer)
Laura C. Fulton
/s/ James M. Whipkey	Chairman of the Board
James M. Whipkey
/s/ John F. Affleck-Graves	Director
John F. Affleck-Graves
/s/ Jefferies V. Alston, III	Director
Jefferies V. Alston, III
/s/ Gregory F. Evans	Director
Gregory F. Evans
/s/ John R. Huff	Director
John R. Huff
/s/ John Kevin Poorman	Director
John Kevin Poorman
/s/ Trevor M. Turbidy	Director
Trevor M. Turbidy
/s/ R. Graham Whaling	Director
R. Graham Whaling
/s/ Joseph C. Winkler III	Director
Joseph C. Winkler III

100

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, 2017 and 2016	F-4
Consolidated Statements of Operations for the years ended December 31, 2017, 2016 and 2015	F-5
Consolidated Statements of Cash Flows for the years ended December 31, 2017, 2016 and 2015	F-6
Consolidated Statements of Partners' Capital for the years ended December 31, 2017, 2016 and 2015	F-8
Notes to Consolidated Financial Statements	F-9

F-1

Report of Independent Registered Public Accounting Firm

To the Board of Directors of Hi-Crush GP LLC and

Unitholders of Hi-Crush Partners LP

Houston, Texas

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheet of Hi-Crush Partners LP and subsidiaries (the "Partnership") as of December 31, 2017, the related consolidated statements of operations, cash flows, and partners’ capital for the year ended December 31, 2017 and the related notes and 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, 2017, and the results of its operations and its cash flows for the year ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America.

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, 2017, 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, 2018, 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 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 the financial statements are free of material misstatement, whether due to error or fraud. Our audit 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 audit 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 audit provides a reasonable basis for our opinion.

/s/ DELOITTE & TOUCHE LLP

February 19, 2018

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 balance sheet as of December 31, 2016 and the related consolidated statements of operations, partners’ capital and cash flows for each of the two years in the period ended December 31, 2016 present fairly, in all material respects, the financial position of Hi-Crush Partners LP and its subsidiaries (the "Partnership") as of December 31, 2016, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2016, in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule for each of the two years in the period ended December 31, 2016, presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits 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 audits provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

February 21, 2017, except for the effects of the merger of entities under common control discussed in Note 4, 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,
	2017		2016 (a)
Assets
Current assets:
Cash	$	5,662	$	4,521
Accounts receivable, net (Note 3)	139,448		52,834
Inventories (Note 5)	44,272		29,277
Prepaid expenses and other current assets	2,832		2,716
Total current assets	192,214		89,348
Property, plant and equipment, net (Note 6)	899,158		541,693
Goodwill and intangible assets, net (Note 7)	8,416		10,097
Equity method investments	17,475		10,232
Other assets	5,877		7,831
Total assets	$	1,123,140	$	659,201
Liabilities, Equity and Partners' Capital
Current liabilities:
Accounts payable	$	46,794	$	19,264
Accrued and other current liabilities (Note 8)	29,931		8,155
Current portion of deferred revenues	4,399		—
Due to sponsor	12,399		118,641
Current portion of long-term debt (Note 9)	2,957		2,962
Total current liabilities	96,480		149,022
Deferred revenues	7,384		—
Long-term debt (Note 9)	194,462		193,458
Asset retirement obligations (Note 10)	10,179		9,514
Other liabilities (Note 11)	19,000		5,000
Total liabilities	327,505		356,994
Commitments and contingencies (Note 11)
Equity and partners' capital:
General partner interest	—		—
Limited partners interest, 89,009,188 and 63,668,244 units outstanding, respectively	795,635		299,516
Total partners' capital	795,635		299,516
Non-controlling interest	—		2,691
Total equity and partners' capital	795,635		302,207
Total liabilities, equity and partners' capital	$	1,123,140	$	659,201

(a) 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-4

HI-CRUSH PARTNERS LP

Consolidated Statements of Operations

(In thousands, except unit and per unit amounts)

	Year Ended December 31,
	2017			2016 (a)			2015 (a)(b)
Revenues	$	602,623		$	204,430		$	339,640
Cost of goods sold (excluding depreciation, depletion and amortization)	438,348			188,308			239,625
Depreciation, depletion and amortization	29,449			17,032			16,613
Gross profit (loss)	134,826			(910		)	83,402
Operating costs and expenses:
General and administrative expenses	39,008			35,501			27,811
Impairments and other expenses (Note 15)	865			34,025			25,659
Accretion of asset retirement obligations (Note 10)	458			430			394
Other operating income	(3,554		)	—			(12,310		)
Income (loss) from operations	98,049			(70,866		)	41,848
Other income (expense):
Earnings from equity method investments	75			—			—
Interest expense	(11,258		)	(13,653		)	(14,126		)
Loss on extinguishment of debt	(4,332		)	—			—
Net income (loss)	$	82,534		$	(84,519	)	$	27,722
Earnings (loss) per limited partner unit:
Basic	$	0.97		$	(1.64	)	$	0.73
Diluted	$	0.96		$	(1.64	)	$	0.73
Weighted average limited partner units outstanding:
Basic	86,518,249			49,567,268			36,958,988
Diluted	87,900,982			49,567,268			37,150,878
Distributions declared per limited partner unit	$	0.35		$	—		$	1.15

(a) Financial information has been recast to include the financial position and results attributable to Hi-Crush Whitehall LLC and Other Assets. See Note 4.

(b) Financial information has been recast to include the financial position and results attributable to Hi-Crush Blair LLC. See Note 4.

See Notes to Consolidated Financial Statements.

F-5

HI-CRUSH PARTNERS LP

Consolidated Statements of Cash Flows

(In thousands)

	Year Ended December 31,
	2017			2016 (a)			2015 (a)(b)
Operating activities:
Net income (loss)	$	82,534		$	(84,519	)	$	27,722
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation and depletion	29,456			17,039			15,684
Amortization of intangible assets	1,681			1,682			2,620
Loss on impairments of goodwill and intangible assets	—			33,745			18,606
Provision for doubtful accounts	—			8,236			—
Unit-based compensation to directors and employees	5,714			2,620			2,983
Amortization of loan origination costs into interest expense	1,391			1,866			2,293
Accretion of asset retirement obligations	458			430			394
(Gain) loss on disposal or impairments of property, plant and equipment	92			(357		)	6,514
Earnings from equity method investments	(75		)	—			—
Loss on extinguishment of debt	4,332			—			—
Changes in operating assets and liabilities:
Accounts receivable	(86,614		)	(19,593		)	40,640
Inventories	(14,529		)	7,270			(6,954		)
Prepaid expenses and other current assets	(119		)	2,190			1,561
Other assets	2,112			1,360			(2,962		)
Accounts payable	25,354			1,277			(2,583		)
Accrued and other current liabilities	21,918			(434		)	(6,326		)
Deferred revenues	11,783			—			—
Due to sponsor	10,781			(797		)	556
Net cash provided by (used in) operating activities	96,269			(27,985		)	100,748
Investing activities:
Capital expenditures for property, plant and equipment	(122,032		)	(44,011		)	(127,217		)
Proceeds from sale of property, plant and equipment	8			1,403			—
Cash used for business combinations	(140,000		)	(75,000		)	—
Cash paid for asset acquisition	(200,830		)	—			—
Equity method investments	(7,168		)	(10,232		)	—
Restricted cash, net	—			—			691
Net cash used in investing activities	(470,022		)	(127,840		)	(126,526		)
Financing activities:
Proceeds from equity issuances, net	412,577			189,037			—
Proceeds from issuance of long-term debt	198,000			—			65,000
Repayment of long-term debt	(198,151		)	(58,396		)	(14,928		)
Loan origination costs	(4,731		)	(128		)	(406		)
Affiliate financing, net	456			16,480			53,512
Proceeds from participants in unit purchase programs	438			111			403
Repurchase of common units	(20,000		)	—			—
Payment of accrued distribution equivalent rights	(39		)	—			—
Distributions paid	(13,656		)	—			(70,072		)
Net cash provided by financing activities	374,894			147,104			33,509
Net increase (decrease) in cash	1,141			(8,721		)	7,731
Cash at beginning of period	4,521			13,242			5,511
Cash at end of period	$	5,662		$	4,521		$	13,242

F-6

	Year Ended December 31,
	2017		2016 (a)			2015 (a)(b)
Non-cash investing and financing activities:
Increase (decrease) in accounts payable and accrued liabilities for additions to property, plant and equipment	$	2,176	$	(8,125	)	$	1,141
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	$	14,000	$	5,000		$	—
Issuance of units for asset acquisition	$	62,242	$	—		$	—
Issuance of units under unit purchase programs	$	1,576	$	—		$	—
Increase (decrease) in accrued distribution equivalent rights	$	45	$	(88	)	$	245
Due to sponsor balance converted into non-controlling interest	$	116,417	$	120,950		$	—
Expense paid by sponsor on behalf of the Partnership	$	—	$	1,652		$	2,787
Cash paid for interest	$	9,867	$	11,787		$	11,833

(a) Financial information has been recast to include the financial position and results attributable to Hi-Crush Whitehall LLC and Other Assets. See Note 4.

(b) Financial information has been recast to include the financial position and results attributable to Hi-Crush Blair LLC. See Note 4.

See Notes to Consolidated Financial Statements.

F-7

HI-CRUSH PARTNERS LP

Consolidated Statements of Partners’ Capital

(In thousands)

	General Partner Capital			Limited Partners
				Common Unit  Capital			Sponsor Subordinated Unit Capital			Total Limited Partner Capital			Total Partner  Capital			Non-Controlling Interest			Total Equity and Partners Capital
Balance at December 31, 2014	$	—		$	190,597		$	(4,172	)	$	186,425		$	186,425		$	2,873		$	189,298
Issuance of 6,344 common units to directors	—			200			—			200			200			—			200
Conversion of subordinated units to common units (b)	—			(21,393		)	21,393			—			—			—			—
Allocation of recast net income (loss) for subordinated units capital (a)	—			5,501			(5,501		)	—			—			—			—
Unit-based compensation expense	—			2,710			—			2,710			2,710			—			2,710
Non-cash contributions by sponsor (b)	—			—			—			—			—			2,787			2,787
Distributions, including distribution equivalent rights	(2,622		)	(42,802		)	(24,893		)	(67,695		)	(70,317		)	—			(70,317		)
Net income (a)(b)	2,622			11,927			13,173			25,100			27,722			—			27,722
Balance at December 31, 2015	—			146,740			—			146,740			146,740			5,660			152,400
Issuance of 19,550,000 common units, net	—			189,037			—			189,037			189,037			—			189,037
Issuance of 103,377 common units to directors	—			453			—			453			453			—			453
Unit-based compensation expense	—			2,146			—			2,146			2,146			—			2,146
Forfeiture of distribution equivalent rights	—			88			—			88			88			—			88
Non-cash contributions by sponsor (a)	—			—			—			—			—			1,652			1,652
Conversion of advances to Hi-Crush Proppants LLC	—			—			—			—			—			120,950			120,950
Acquisition of Hi-Crush Blair LLC	—			45,571			—			45,571			45,571			(125,571		)	(80,000		)
Net loss (a)	—			(84,519		)	—			(84,519		)	(84,519		)	—			(84,519		)
Balance at December 31, 2016	—			299,516			—			299,516			299,516			2,691			302,207
Issuance of 23,575,000 common units, net	—			412,577			—			412,577			412,577			—			412,577
Issuance of 3,438,789 common units for asset acquisition	—			62,242			—			62,242			62,242			—			62,242
Issuance of 329,238 common units to directors and employees	—			2,144			—			2,144			2,144			—			2,144
Repurchase of 2,030,163 common units	—			(20,000		)	—			(20,000		)	(20,000		)	—			(20,000		)
Unit-based compensation expense	—			5,215			—			5,215			5,215			—			5,215
Distributions, including distribution equivalent rights	—			(13,808		)	—			(13,808		)	(13,808		)	—			(13,808		)
Forfeiture of distribution equivalent rights	—			107			—			107			107			—			107
Conversion of advances to Hi-Crush Proppants LLC	—			—			—			—			—			116,417			116,417
Acquisition of Hi-Crush Whitehall LLC and Other Assets	—			(34,892		)	—			(34,892		)	(34,892		)	(119,108		)	(154,000		)
Net income	—			82,534			—			82,534			82,534			—			82,534
Balance at December 31, 2017	$	—		$	795,635		$	—		$	795,635		$	795,635		$	—		$	795,635

(a) Financial information has been recast to include the financial position and results attributable to Hi-Crush Whitehall LLC and Other Assets. See Note 4.

(b) Financial information has been recast to include the financial position and results attributable to Hi-Crush Blair LLC. See Note 4.

See Notes to Consolidated Financial Statements.

F-8

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" or "Hi-Crush GP"), and a 100% limited partner interest to Hi-Crush Proppants LLC (the "sponsor"), its organizational limited partner. The Partnership is a premier provider of proppant and logistics solutions to the North American energy industry. Our portfolio of production facilities produces high-quality monocrystalline sand, a specialized mineral used as a proppant during the well completion process, necessary to facilitate the recovery of hydrocarbons from oil and natural gas wells. Our Wisconsin production facilities' have direct access to major U.S. railroads and our strategically located owned and operated in-basin terminals as well as our Texas production facility positions us within close proximity to significant activity in all major oil and gas basins. Our integrated distribution system, including our PropStream^TM logistics service, delivers proppant the "last mile" into the blender.

On January 31, 2013 and April 8, 2014, the Partnership entered into agreements with the sponsor which ultimately resulted in the acquisition of 98.0% of the common equity interests in Hi-Crush Augusta LLC ("Augusta"), the entity that owned the sponsor’s Augusta raw frac sand processing facility.

On June 10, 2013, the Partnership acquired an independent frac sand supplier, D & I Silica, LLC ("D&I"), transforming the Partnership into an integrated Northern White frac sand producer, transporter, marketer and distributor. Founded in 2006, D&I was the largest independent frac sand supplier to the oil and gas industry drilling in the Marcellus and Utica shale plays.

On August 9, 2016, the Partnership entered into a contribution agreement with the sponsor to acquire all of the outstanding membership interests in Hi-Crush Blair LLC ("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 "Blair Contribution"). The Partnership completed the acquisition of the Blair facility on August 31, 2016.

On February 23, 2017, the Partnership entered into a contribution agreement with our sponsor to acquire 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 Augusta, and all of the outstanding membership interests in PDQ Properties LLC (together, the "Other Assets"), for $140,000 in cash and up to $65,000 of contingent consideration over a two-year period (the "Whitehall Contribution"). The Partnership completed this acquisition on March 15, 2017.

On March 3, 2017, the Partnership completed an acquisition of Permian Basin Sand Company, LLC ("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. 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, within 75 miles of significant Delaware and Midland Basin activity.

2. Basis of Presentation

The Blair Contribution and Whitehall Contribution were accounted for as transactions between entities under common control whereby the net assets of Blair, Whitehall and Other Assets were recorded at their historical cost. Therefore, the Partnership's historical financial information has been recast to combine 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 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-9

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 raw 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 December 31, 2017 and 2016, the Partnership maintained an allowance for doubtful accounts of $1,060 and $1,549, respectively. 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.

Deferred 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 $1,391, $1,866 and $2,293 for the years ended December 31, 2017, 2016 and 2015, respectively.

On December 22, 2017, the Partnership replaced our amended and restated credit agreement (the "Prior Revolving Credit Agreement") and our 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.

On April 28, 2016 and November 5, 2015, we amended our Prior Revolving Credit Agreement. As a result of these modifications, we accelerated amortization of $349 and $662, respectively, representing a portion of the remaining unamortized balance of debt issuance costs, which is included in interest expense.

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. In connection with the refinancing in December 2017, the Partnership incurred debt issuance costs of $4,731 that were capitalized. As of December 31, 2017 and 2016, the Partnership maintained unamortized debt issuance costs of $3,643 and $3,538 within long-term debt, respectively and $1,070 and $913 within other assets, respectively. Balances maintained in other assets represent costs associated with our revolving credit facility. Refer to Note 9 - Long-Term Debt for additional disclosure on our Revolving Credit Agreement and Term Loan Credit Facility.

F-10

HI-CRUSH PARTNERS LP

Notes to Consolidated Financial Statements

(Dollars in thousands, except unit and per unit amounts, or where otherwise noted)

The following is a summary of future amortization expense associated with deferred charges:

For the years ending December 31,
2018	$	673
2019	673
2020	673
2021	673
2022	673
Thereafter	1,348
Total	$	4,713

Inventories

Sand inventory is stated at the lower of cost or net realizable value using the average cost method.

Inventory manufactured at our plant 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.

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 line in the balance sheet.

F-11

HI-CRUSH PARTNERS LP

Notes to Consolidated Financial Statements

(Dollars in thousands, except unit and per unit amounts, or where otherwise noted)

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.

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.

During the year ended December 31, 2015, we elected to idle five destination transload facilities and three rail origin transload facilities.  In addition, to consolidate our administrative functions, we closed down a regional office facility. As a result of these actions, we recognized an impairment of $6,186 related to the write-down of transload and office facilities assets to their net realizable value. No impairment charges were recorded during the years ended December 31, 2017 and 2016. Refer to Note 15 - Impairments and Other Expenses for additional disclosure regarding impairments.

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 all goodwill. Refer to Note 15 - Impairments and Other 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. During the year ended December 31, 2015, we completed an impairment assessment of the intangible asset associated with a third party supply agreement (the "Sand Supply Agreement").  Given market conditions, coupled with our ability to internally produce sand on more favorable terms, we determined that the fair value of the agreement was less than its carrying value, resulting in an impairment of $18,606. The Partnership did not recognize any impairments for intangible assets during the years ended December 31, 2017 and 2016. Refer to Note 15 - Impairments and Other Expenses for additional disclosure regarding impairments.

F-12

HI-CRUSH PARTNERS LP

Notes to Consolidated Financial Statements

(Dollars in thousands, except unit and per unit amounts, or where otherwise noted)

Equity Method Investments

The Partnership accounts for investments, which 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.

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. As of December 31, 2017, the Partnership's investment basis in PropX was $17,475, which is accounted for as an equity method investment as the Partnership has a non-controlling interest in PropX, but has the ability to exercise significant influence. During the years ended December 31, 2017 and 2016, the Partnership made capital contributions of $7,168 and $10,232, respectively, to PropX. During the year ended December 31, 2017, we recognized earnings of $75 from our proportionate share of PropX's operating results. During the year ended December 31, 2016, we did not recognize any earnings from our proportionate share of PropX's operating results.

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.  In connection with its recent acquisitions of Blair and Whitehall and Other Assets from its sponsor, the Partnership has entered into certain contingent consideration arrangements.  As such transactions are between entities under common control, any differences between the calculated fair value, and the actual resulting payments in the future will be 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

Frac sand sales revenues are recognized when legal title passes to the customer, which may occur at the production facility, rail origin, terminal or wellsite. At that point, delivery has occurred, evidence of a contractual arrangement exists and collectability is reasonably assured. Amounts received from customers in advance of sand deliveries are recorded as deferred revenue. As of December 31, 2017, the Partnership has recorded a total liability of $11,783 for prepayments of future deliveries of frac sand. These prepayments are refundable in the event that the Partnership is unable to meet the minimum sand volumes required under the contract.

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 2018 and 2024. The agreements define, among other commitments, the volume of product that the Partnership must provide, the price that will be charged to the customer, and the volume that the customer must purchase by the end of the defined cure periods, which can range from three months to the end of a contract year.

Revenue from make-whole provisions in our customer contracts is recognized at the end of the defined cure period when collectability is certain. Customer prepayments in excess of customer obligations remaining on account upon the termination of a contract are recognized as other operating income during the period in which the 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. During the year ended December 31, 2015, the Partnership recognized $12,310 as part of a settlement payment for past and future obligations under a customer contract, which is included in other operating income on our Consolidated Statements of Operations.

Transportation services revenues are recognized as the services have been completed, meaning the related services have been rendered. At that point, delivery of service has occurred, evidence of a contractual arrangement exists and collectability is reasonably assured.

F-13

HI-CRUSH PARTNERS LP

Notes to Consolidated Financial Statements

(Dollars in thousands, except unit and per unit amounts, or where otherwise noted)

Fair Value of Financial Instruments

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 fair value of the senior secured term loan approximated $198,015 as of December 31, 2017, based on the market price quoted from external sources, compared with a carrying value of $200,000. If the senior secured term loan was measured at fair value in the financial statements, it would be classified as Level 2 in the fair value hierarchy.

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.

As described in Note 2 - Basis of Presentation, the Partnership's historical financial information has been recast to consolidate Blair, Whitehall and Other Assets for all periods presented. The amounts of incremental income or losses recast to periods prior to the 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, 2017 and 2016, the Partnership did not have any liabilities for uncertain tax positions or gross unrecognized tax benefits.

Recent Accounting Pronouncements

In May 2017, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update No. 2017-09 ("ASU 2017-09"), Compensation - Stock Compensation (Topic 718): Scope of Modification Accounting. This update provides guidance about which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting in Topic 718. The amendments in this update will be applied prospectively to an award modified on or after the adoption date. ASU 2017-09 is effective for the Partnership beginning after December 15, 2017, with early adoption permitted. The Partnership is currently assessing the impact that adopting this new accounting guidance will have on its Consolidated Financial Statements and footnote disclosures.

In January 2017, the FASB issued Accounting Standards Update No. 2017-03 ("ASU 2017-03"), Accounting Changes and Error Corrections (Topic 250) and Investments-Equity Method and Joint Ventures (Topic 323): Amendments to SEC Paragraphs Pursuant to Staff Announcements at the September 22, 2016 and November 17, 2016 EITF Meetings. This update adds language to the SEC Staff Guidance in relation to ASU 2014-09, ASU 2016-02, and ASU 2016-13. This ASU 2017-03 provides the SEC Staff view that a registrant should consider additional quantitative and qualitative disclosures related to the previously mentioned ASUs in connection with the status and impact of their adoption. This guidance, which was effective immediately, did not have a material impact on our Consolidated Financial Statements.

In January 2017, the FASB issued Accounting Standards Update No. 2017-01 ("ASU 2017-01"), Business Combinations (Topic 805): Clarifying the Definition of a Business. This update clarifies the definition of a business and provides additional guidance for determining whether transactions should be accounted for as acquisitions of assets or business. The amendment was effective for the Partnership beginning January 1, 2018, with early adoption permitted, and should be applied prospectively. The Partnership is currently assessing the impact that adopting this new accounting guidance will have on its Consolidated Financial Statements and footnote disclosures, but does not anticipate that adoption will have a material impact on its financial position, results of operations or cash flows.

F-14

HI-CRUSH PARTNERS LP

Notes to Consolidated Financial Statements

(Dollars in thousands, except unit and per unit amounts, or where otherwise noted)

In February 2016, the FASB issued Accounting Standards Update No. 2016-02 ("ASU 2016-02"), Leases (Topic 842). This update will impact all leases with durations greater than twelve months. In general, such arrangements will be 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 will be recorded for all leases, whether operating or financing, while the statement of operations will reflect 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 will be calculated using the applicable incremental borrowing rate at the date of adoption. The new accounting guidance is effective for the Partnership beginning in the first quarter of 2019, and should be applied retrospectively. The FASB has also issued the following standard which clarifies ASU 2016-02 and has 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). The Partnership is currently assessing the impact that adopting this new accounting guidance will have on its Consolidated Financial Statements and footnote disclosures.

In May 2014, the FASB issued Accounting Standards Update No. 2014-09 ("ASU 2014-09"), Revenue from Contracts with Customers (Topic 606). This update supersedes the most current revenue recognition guidance, as well as some cost recognition guidance. The update requires that an entity recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This update also requires new qualitative and quantitative disclosures about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts, including significant judgments and changes in judgments, information about contract balances and performance obligations, and assets recognized from costs incurred to obtain or fulfill a contract. The authoritative guidance, which may be applied on a full retrospective or modified retrospective basis whereby the entity records a cumulative effect of initially applying this update at the date of initial application, was effective for the Partnership beginning January 1, 2018. The FASB has also issued the following standards which clarify ASU 2014-09 and have the same effective date as the original standard: ASU 2016-12, Revenue from Contracts with Customers: Narrow- Scope Improvements and Practical Expedients, ASU 2016-10 Revenue from Contracts with Customers: Identifying Performance Obligations and Licensing and ASU 2017-13, Revenue Recognition (Topic 605), Revenue from Contracts with Customers (Topic 606), Leases (Topic 840), and Leases (Topic 842).

The Partnership has completed its assessment of the impacts of the adoption of ASU 2014-09. We adopted ASU 2014-09 on January 1, 2018, using the full retrospective approach and it will be fully presented in the Partnership’s Quarterly Report on Form 10-Q for the three months ended March 31, 2018. We finalized the documentation on our assessment of our contracts and determined that there is no impact on our revenue recognition practices or impact to our Consolidated Financial Statements. The adoption of ASU 2014-09 will also result in additional disclosures regarding revenue recognition, disaggregation of revenue types and deferred revenue contract liabilities. The Partnership generates revenue by excavating, processing and delivering frac sand and providing related services and recognizes revenue at the point of delivery to customers or completion of services, at which point the earnings process is deemed to be complete. Amounts received from customers in advance of sand deliveries are recorded as deferred revenue.

4. Acquisitions

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. With the acquisition of Permian Basin Sand, we acquired 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

F-15

HI-CRUSH PARTNERS LP

Notes to Consolidated Financial Statements

(Dollars in thousands, except unit and per unit amounts, or where otherwise noted)

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.

The contingent consideration is 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. If those annual thresholds are met, the Partnership will pay an additional $20,000 for each threshold met or exceeded. The Partnership anticipates payment of $20,000 of contingent consideration with respect to the 2017 measurement period in March 2018 to our sponsor pending approval from the conflicts committee. If the Partnership exceeds a total threshold for the cumulative two-year period, then it will pay an additional $25,000, for an undiscounted total of up to $65,000 to be paid in cash or common units at the Partnership's discretion. 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, as reflected in other liabilities on our Consolidated Balance Sheet. Refer to Note 11 - Commitments and Contingencies for additional disclosure regarding the contingent consideration.

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. Any material transactions between the Partnership, Whitehall and Other Assets have been eliminated. The balance of non-controlling interest as of December 31, 2016 includes the sponsor's interest in Whitehall and Other Assets prior to the combination. Except for the combination of the Consolidated Statements of Operations and the respective allocation of recast net income (loss), capital transactions between the sponsor and Whitehall and Other Assets prior to March 15, 2017 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 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 liabilities 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 payable in the future.

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 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 is based on the Partnership's Adjusted EBITDA exceeding certain thresholds for each of the fiscal years ending December 31, 2017 and 2018. If the Partnership exceeds either or both of the respective thresholds, then it will pay an additional $5,000 for each threshold met or exceeded, for an undiscounted total of up to $10,000. The Partnership anticipates payment of $5,000 of contingent consideration with respect to the 2017 measurement period in March 2018 to our sponsor pending approval from the conflicts committee. 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, as reflected in other liabilities on our Consolidated Balance Sheet. Refer to Note 11 - Commitments and Contingencies for additional disclosure regarding the contingent consideration.

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. Any material transactions between the Partnership and Blair have been eliminated. The balance of non-controlling interest as of December 31, 2016 includes the sponsor's interest in Blair prior to the combination. Except for the combination of the Consolidated Statements of Operations and the respective allocation of recast net income (loss), capital transactions between the sponsor and Blair prior to August 31, 2016 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 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 liabilities 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 payable in the future.

F-17

HI-CRUSH PARTNERS LP

Notes to Consolidated Financial Statements

(Dollars in thousands, except unit and per unit amounts, or where otherwise noted)

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 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, 2017
	Partnership Historical		Whitehall and Other Assets through  March 15, 2017			Eliminations			Partnership Recast (Supplemental)
Revenues	$	602,623	$	—		$	—		$	602,623
Net income (loss)	$	83,979	$	(1,366	)	$	(79	)	$	82,534
Net income (loss) attributable to Hi-Crush Partners LP	$	84,005	$	(1,392	)	$	(79	)	$	82,534
Net income per limited partner unit - basic	$	0.97							$	0.95

	Year Ended December 31, 2016
	Partnership Historical			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	)	$	716	$	(3,778	)	$	(45	)	$	(84,519	)
Net income (loss) attributable to Hi-Crush Partners LP	$	(81,313	)	$	716	$	(3,877	)	$	(45	)	$	(84,519	)
Net loss per limited partner unit - basic	$	(1.64	)									$	(1.71	)

	Year Ended December 31, 2015
	Partnership Historical		Blair			Whitehall and Other Assets		Eliminations			Partnership Recast (Supplemental)
Revenues	$	339,640	$	—		$	33,217	$	(33,217	)	$	339,640
Net income (loss)	$	28,410	$	(2,619	)	$	1,645	$	286		$	27,722
Net income (loss) attributable to Hi-Crush Partners LP	$	28,265	$	(2,619	)	$	1,790	$	286		$	27,722
Net income per limited partner unit - basic	$	0.73									$	0.71

5. Inventories

Inventories consisted of the following:

	December 31,
	2017		2016
Raw material	$	498	$	—
Work-in-process	18,739		17,836
Finished goods	22,892		9,416
Spare parts	2,143		2,025
Inventories	$	44,272	$	29,277

F-18

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,
	2017			2016
Buildings	$	21,532		$	16,929
Mining property and mine development	381,653			113,169
Plant and equipment	389,197			331,165
Rail and rail equipment	55,783			56,369
Transload facilities and equipment	121,522			78,105
Construction-in-progress	14,454			1,695
Property, plant and equipment	984,141			597,432
Less: Accumulated depreciation and depletion	(84,983		)	(55,739		)
Property, plant and equipment, net	$	899,158		$	541,693

Depreciation and depletion expense was $29,456, $17,039 and $15,684 for the years ended December 31, 2017, 2016 and 2015, respectively.

The Partnership recognized a (gain) loss on the disposal of fixed assets of $92, $(357) and $72 during the years ended December 31, 2017, 2016 and 2015, respectively, which are included in general and administrative expenses on our Consolidated Statements of Operations.

During the year ended December 31, 2016, the Partnership entered into an agreement to terminate certain existing royalty obligations for $6,750, of which $3,375 was paid during each of September 2017 and 2016. As a result of this agreement, the Partnership reduced its ongoing future royalty payments to the applicable counterparties for each ton of frac sand that is excavated, processed and sold to the Partnership’s customers. As of part of this transaction, we recorded an asset of $6,750, as reflected in property, plant and equipment on the Consolidated Balance Sheet.

As a result of market conditions, the Augusta facility was temporarily idled from October 2015 through September 2016 and the Whitehall facility was temporarily idled during the second quarter of 2016 and resumed operations in March 2017. No impairments were recorded related to the Augusta and Whitehall facilities.

During the year ended December 31, 2015, the Partnership recognized an impairment of $6,186 related to the write-down of transload and office facilities assets to their net realizable value and recognized expense of $256 related to the abandonment of certain transload construction projects. These expenses are included in impairments and other expenses in our Consolidated Statements of Operations. Refer to Note 15 - Impairments and Other Expenses for additional disclosure regarding impairments.

7. Goodwill and Intangible Assets

Changes in goodwill and intangible assets consisted of the following:

	Goodwill			Intangible Assets
Balance at December 31, 2015	$	33,745		$	11,779
Loss on impairment (Note 15)	(33,745		)	—
Amortization expense	—			(1,682		)
Balance at December 31, 2016	—			10,097
Amortization expense	—			(1,681		)
Balance at December 31, 2017	$	—		$	8,416

Goodwill

During the year ended December 31, 2016, the Partnership recognized a $33,745 impairment loss of all goodwill that was allocated from the purchase price of its acquisition of D&I in 2013. Refer to Note 15 - Impairments and Other Expenses for additional disclosure regarding our goodwill impairment assessment.

F-19

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 D&I consisted of the following:

		December 31,
	Useful life	2017			2016
Supplier agreements	1-20 Years	$	21,997		$	21,997
Customer contracts and relationships	1-10 Years	18,132			18,132
Other intangible assets	1-3 Years	1,749			1,749
Intangible assets		41,878			41,878
Less: Accumulated amortization and impairments		(33,462		)	(31,781		)
Intangible assets, net		$	8,416		$	10,097

Amortization expense was $1,681 and $1,682 for the years ended December 31, 2017 and 2016, respectively. As of December 31, 2017, the unamortized balance of intangible assets is associated with our customer relationships. The weighted average remaining life of intangible assets was 5 years as of December 31, 2017.

During the year ended December 31, 2015, we completed an impairment assessment of the intangible asset associated with the Sand Supply Agreement.  Given current market conditions, coupled with our ability to internally produce sand on more favorable terms, we determined that the fair value of the agreement was less than its carrying value, resulting in an impairment of $18,606. The Partnership did not recognize any impairments for intangible assets during the years ended December 31, 2017 and 2016, respectively. Refer to Note 15 - Impairments and Other Expenses for additional disclosure regarding impairments.

As of December 31, 2017, future amortization is as follows:

Fiscal Year	Amortization
2018	$	1,682
2019	1,682
2020	1,682
2021	1,682
2022	1,682
Thereafter	6
	$	8,416

8. Accrued and Other Current Liabilities

Accrued and other current liabilities consisted of the following:

	December 31,
	2017		2016
Accrued royalty payments	$	8,763	$	3,436
Accrued logistics costs	5,878		763
Accrued compensation and benefits	7,150		1,833
Accrued taxes payable	5,139		389
Accrued interest payable	505		339
Other current liabilities	2,496		1,395
Accrued and other current liabilities	$	29,931	$	8,155

F-20

HI-CRUSH PARTNERS LP

Notes to Consolidated Financial Statements

(Dollars in thousands, except unit and per unit amounts, or where otherwise noted)

9. Long-Term Debt

Long-term debt consisted of the following:

	December 31,
	2017			2016
Revolving Credit Agreement	$	—		$	—
Prior Revolving Credit Agreement	—			—
Term Loan Credit Facility	200,000			—
Prior Term Loan Credit Facility	—			194,500
Less: Unamortized original issue discount	(1,992		)	(1,247		)
Less: Unamortized debt issuance costs	(3,643		)	(3,538		)
Other notes payable	3,054			6,705
Total debt	197,419			196,420
Less: current portion of long-term debt	(2,957		)	(2,962		)
Long-term debt	$	194,462		$	193,458

Revolving Credit Agreement

On April 28, 2014, the Partnership entered into a five-year amended and restated credit agreement (the "Prior Revolving Credit Agreement"). On August 31, 2016, the Partnership entered into a fourth amendment to the Prior Revolving Credit Agreement, which allowed for the Blair Contribution. On March 3, 2017, the Partnership entered into a fifth amendment to the Prior Revolving Credit Agreement, which allowed for the Whitehall Contribution and the acquisition of Permian Basin Sand. On October 12, 2017, the Partnership entered into a sixth amendment to the Prior Revolving Credit Agreement, which allowed the Partnership to make repurchases of common units up to $20,000. The Prior Revolving Credit Agreement, as amended, was a senior secured revolving credit facility that permitted aggregate borrowings of up to $75,000, including a $25,000 sublimit for letters of credit and a $10,000 sublimit for swing line loans. The outstanding balance under the Prior Revolving Credit Agreement was paid in full during the second quarter of 2016.

On December 22, 2017, the Partnership replaced the Prior Revolving Credit Agreement by entering into a second amended and restated credit agreement (the "Revolving Credit Agreement"), which matures on December 22, 2022. As of December 31, 2017, the Revolving Credit Agreement, as amended, is a senior secured revolving credit facility that permits aggregate borrowings of up to $125,000, including a $30,000 sublimit for letters of credit and a $10,000 sublimit for swing line loans.

As of December 31, 2017, we had $104,334 of undrawn borrowing capacity ($125,000, net of $20,666 letter of credit commitments) and no indebtedness under our Revolving Credit Agreement.

Borrowings under the Revolving Credit Agreement, as amended, bear interest at a rate equal to, at the Partnership's option, either (1) a base rate plus an applicable margin ranging between 1.50% per annum and 2.25% per annum, based upon the Partnership's leverage ratio, or (2) a Eurodollar rate plus an applicable margin ranging between 2.50% per annum and 3.25% per annum, based upon the Partnership's leverage ratio.

The Revolving Credit Agreement 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. The Revolving Credit Agreement requires compliance with customary financial covenants, which are a maximum leverage ratio of 3.25x, a minimum interest coverage ratio of 2.5x and an asset coverage ratio of 1.5x. The Revolving Credit Agreement generally permits repurchases of common units.

As of December 31, 2017, we are in compliance with the covenants contained in the Revolving Credit Agreement. Our ability to comply with such covenants in the future, and access our undrawn borrowing capacity under our Revolving Credit Agreement, is dependent primarily on achieving certain levels of EBITDA, as defined. The Revolving Credit Agreement provides for an "equity cure" that can be applied to EBITDA covenant ratios. Refer to Note 12 - Equity for information regarding our equity distribution program.

F-21

HI-CRUSH PARTNERS LP

Notes to Consolidated Financial Statements

(Dollars in thousands, except unit and per unit amounts, or where otherwise noted)

The Revolving Credit Agreement contains customary events of default (some of which are subject to applicable grace or cure periods), including among other things, non-payment defaults, covenant defaults, cross-defaults to other material indebtedness, bankruptcy and insolvency defaults, and material judgment defaults. Such events of default could entitle the lenders to cause any or all of the Partnership’s indebtedness under the Revolving Credit Agreement to become immediately due and payable. If such a default were to occur, and resulted in a cross default of the Term Loan Credit Agreement, as described below, all of our outstanding debt obligations could be accelerated which would have a material adverse impact on the Partnership.

The Revolving Credit Agreement is secured by substantially all assets of the Partnership. In addition, the Partnership's subsidiaries have guaranteed the Partnership's obligations under the Revolving Credit Agreement and have granted to the revolving lenders security interests in substantially all of their respective assets.

Term Loan Credit Facility

On April 28, 2014, the Partnership entered into a credit agreement (the "Prior Term Loan Credit Agreement") providing for a seven-year senior secured term loan credit facility (the "Prior Term Loan Credit Facility") that permits aggregate borrowings of up to $200,000, which was fully drawn on April 28, 2014. On December 22, 2017, the outstanding balance under the Prior Term Loan Credit Facility was paid in full.

On December 22, 2017, the Partnership replaced the Prior Term Loan Credit Agreement by entering into an amended and restated credit agreement (the "Term Loan 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. The Term Loan Credit Agreement permits the Partnership, at its option, to add one or more incremental term loan facilities in an aggregate amount not to exceed $100,000. Any incremental term loan facility would be on terms to be agreed among the Partnership, the administrative agent and the lenders who agree to participate in the incremental facility. The maturity date of the Term Loan Credit Facility is December 22, 2024.

The Term Loan Credit Agreement is secured by substantially all assets of the Partnership. In addition, the Partnership’s subsidiaries have guaranteed the Partnership’s obligations under the Term Loan Credit Agreement and have granted to the lenders security interests in substantially all of their respective assets.

Borrowings under the Term Loan Credit Agreement bear interest at a rate equal to, at the Partnership’s option, either (1) a base rate plus an applicable margin of 2.75% per annum or (2) a Eurodollar rate plus an applicable margin of 3.75% per annum, subject to a LIBOR floor of 1.00%. Both base rate loans and Eurodollar loans are subject to a 0.25% rate increase during any period of time in which the Partnership does not have a public company family rating of B2 or better from Moody's Investors Service Inc. ("Moody's"). As of February 15, 2018, the credit rating of the Partnership’s senior secured term loan credit facility was B3 from Moody’s and B- from Standard and Poor’s.

The Term Loan Credit Agreement 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 addition, it contains customary events of default that entitle the lenders to cause any or all of the Partnership’s indebtedness under the Term Loan Credit Agreement 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, 2017, we were in compliance with the terms of the agreement.

As of December 31, 2017, we had $194,365 indebtedness ($200,000, net of $1,992 of discounts and $3,643 of debt issuance costs) under our Term Loan Credit Facility, which carried an interest rate of 5.41%.

Other Notes Payable

On October 24, 2014, the Partnership entered into a purchase and sales agreement to acquire land and underlying frac sand deposits. During the years ended December 31, 2016, 2015 and 2014, the Partnership paid cash consideration of $2,500, and issued a three-year promissory note in the amount of $3,676, respectively, in connection with this agreement. 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 in December 2019, December 2018 and October 2017. 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.

During the years ended December 31, 2017 and 2016, the Partnership made prepayments of $3,651 and $3,896, respectively, based on the accumulated volume of sand extracted, delivered, sold and paid for. In January 2018, the Partnership made a prepayment of $957 based on the volume of sand extracted, delivered, sold and paid for through the fourth quarter of 2017. As of December 31, 2017, the Partnership had repaid in full the promissory note due in October 2017 and December 2018 and we had $3,054 outstanding on our remaining promissory note, which carried interest rate of 0.74%.

F-22

HI-CRUSH PARTNERS LP

Notes to Consolidated Financial Statements

(Dollars in thousands, except unit and per unit amounts, or where otherwise noted)

Maturities

As of December 31, 2017, future minimum debt repayments, excluding original issue discount and debt issuance costs, are as follows:

Fiscal Year	Amount
2018	$	2,957
2019	4,097
2020	2,000
2021	2,000
2022	2,000
Thereafter	190,000
	$	203,054

10. 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, 2014	$	8,317
Accretion expense	394
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

11. 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, 2017, no payments for non-delivery of minimum annual sand volumes have been made by the Partnership to customers under these contracts.

Supplier Contracts

D&I has entered into a long-term supply agreement with a supplier (the "Sand Supply Agreement"), which includes a requirement to purchase certain volumes and grades of sands at specified prices. The quantities set forth in such agreement are not in excess of our current requirements.

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 $19,091, $6,725 and $13,660 for the years ended December 31, 2017, 2016 and 2015, respectively.

F-23

HI-CRUSH PARTNERS LP

Notes to Consolidated Financial Statements

(Dollars in thousands, except unit and per unit amounts, or where otherwise noted)

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 day time frame, we are obligated to purchase the property for fair market value.

As of December 31, 2017, 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, 2017, the Partnership has paid $2,188 under these guarantees.

Lease Obligations

The Partnership has long-term leases for railcars, equipment and certain of its terminals. Railcar rental expense was $27,410, $28,597 and $22,027 for the years ended December 31, 2017, 2016 and 2015, 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 $1,577 and $124 for the years ended December 31, 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. However, the minimum quantities set forth in the agreements are not in excess of our current forecasted requirements at these locations.

As of December 31, 2017, future minimum operating lease payments and minimum purchase commitments are as follows:

Fiscal Year	Operating Leases		Minimum Purchase Commitments
2018	$	33,787	$	5,571
2019	33,638		2,616
2020	30,831		2,296
2021	24,068		2,296
2022	18,036		2,296
Thereafter	16,670		1,871
	$	157,030	$	16,946

In addition, the Partnership has placed orders for additional leased railcars. Such long-term operating leases commence upon the future delivery of 700 railcars, which are scheduled to be delivered during the first half of 2018.

Equity Method Investments

On September 8, 2016, the Partnership committed to investing up to $17,400 in PropX over the next year to 18 months for use in the manufacturing of containers and conveyor systems, among other things. As of December 31, 2017, the Partnership has funded all of its commitment to PropX, of which $7,168 was funded during the year ended December 31, 2017.

F-24

HI-CRUSH PARTNERS LP

Notes to Consolidated Financial Statements

(Dollars in thousands, except unit and per unit amounts, or where otherwise noted)

Contingent Consideration

As described in Note 4 - Acquisitions, the Partnership may pay the sponsor up to $10,000 and $65,000 of contingent consideration related to the Blair Contribution and the Whitehall Contribution, respectively.  The payments are based on achievement of certain levels of Adjusted EBITDA in 2017 and 2018.  Achievement of these threshold levels of Adjusted EBITDA, as defined in each of the contribution agreements, will be dependent on the quantity of volumes sold and related prices, which are forecasted at levels above current market prices.  The Partnership’s ability to meet such thresholds will be affected by events and circumstances beyond its control.  If market or other economic conditions remain the same or deteriorate, the thresholds may not be met. If the thresholds are not attained during each of the contingency periods, no payment will be owed to the sponsor.

A 10% increase or decrease in the achievement of Adjusted EBITDA versus current forecasts for the measurement periods could result in a range of potential payments under these arrangements which could differ from the current estimated fair value of the liabilities based on our current forecasts.  The following table outlines the original fair value reflected as the carrying value in the financial statements, the range of minimum and maximum undiscounted payments, and a sensitivity calculation of the current estimated fair value and sensitivities based on achieving Adjusted EBITDA levels 10% above or below the Partnership’s current forecasted results as of December 31, 2017.  Based on the significant estimates and assumptions included in the analysis, actual results could differ from these estimates.

			Undiscounted Payments				Sensitivity Analysis
Transaction	Carrying Value of Liability		Minimum (a)		Maximum		Current Estimated Fair Value		-10% Adjusted EBITDA		+10% Adjusted EBITDA
Blair Contribution	$	5,000	$	5,000	$	10,000	$	7,226	$	7,226	$	7,226
Whitehall Contribution	$	14,000	$	20,000	$	65,000	$	20,000	$	20,000	$	20,000

(a) The Partnership anticipates payment of $5,000 and $20,000 for the 2017 measurement periods related to the Blair Contribution and the Whitehall Contribution, respectively, in March 2018 to our sponsor pending approval from the conflicts committee.

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.

12. Equity

During the second quarter of 2017, our sponsor distributed its 20,693,643 common units in the Partnership to its members. As of December 31, 2017, our management team, together with our general partner's board of directors have a 10% direct ownership interest in our limited partnership units. In addition, our sponsor is the owner of our general partner.

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.

During the year ended December 31, 2017, the Partnership repurchased 2,030,163 common units for a total cost of $20,000 at an average price including commissions of $9.82 per unit.

F-25

HI-CRUSH PARTNERS LP

Notes to Consolidated Financial Statements

(Dollars in thousands, except unit and per unit amounts, or where otherwise noted)

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 did not issue 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. Our sponsor currently holds the incentive distribution rights, but may transfer these rights at any time.

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 are made after giving effect, if any, to priority income allocations in an amount equal to incentive cash distributions allocated 100% to our sponsor.

During the years ended December 31, 2017 and 2016, no income was allocated to our holders of incentive distribution rights. During the year ended December 31, 2015, $2,622 was allocated to our holders of 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 and our holders of incentive distribution rights will receive.

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 Holders of Incentive Distribution Rights
January 15, 2015	$	0.6750	January 30, 2015	February 13, 2015	$	24,947	$	1,311
April 16, 2015	$	0.6750	May 1, 2015	May 15, 2015	$	24,947	$	1,311
July 21, 2015	$	0.4750	August 5, 2015	August 14, 2015	$	17,555	$	—
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	$	—

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.

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,
	2017	2016	2015
Basic common units outstanding	86,518,249	49,567,268	36,958,988
Potentially dilutive common units	1,382,733	—	191,890
Diluted common units outstanding	87,900,982	49,567,268	37,150,878

For purposes of calculating the Partnership’s earnings per unit under the two-class method, common units are treated as participating preferred units, and the previously outstanding subordinated units were treated as the residual equity interest, or common equity. Incentive distribution rights are treated as participating securities.

F-26

HI-CRUSH PARTNERS LP

Notes to Consolidated Financial Statements

(Dollars in thousands, except unit and per unit amounts, or where otherwise noted)

Diluted earnings per unit excludes any dilutive awards granted (see Note 13 - Unit-Based Compensation) if their effect is anti-dilutive. Diluted earnings per unit for the years ended December 31, 2017 and 2015, includes the dilutive effect of 1,382,733 and 191,890, 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 holders is subject to the distribution waterfall in the partnership agreement. 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 Blair, Whitehall and Other Assets for all periods presented. The amounts of incremental income or losses recast to periods prior to the 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, 2017, 2016 and 2015 (in thousands, except per unit amounts):

	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	—		51,077		51,077
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	—		(84,519		)	(84,519		)
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	)

F-27

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, 2015
	General Partner and IDRs		Limited Partner Units			Total
Declared distribution	$	1,311	$	42,502		$	43,813
Assumed allocation of distributions in excess of earnings	—		(16,091		)	(16,091		)
Add back recast losses attributable to Blair	—		2,619			2,619
Add back recast income attributable to Whitehall and Other Assets	—		(2,076		)	(2,076		)
Assumed allocation of net income	$	1,311	$	26,954		$	28,265
Earnings per limited partner unit - basic			$	0.73
Earnings per limited partner unit - diluted			$	0.73

Recast Equity Transactions

On March 15, 2017, in connection with the closing of the Whitehall Contribution, $116,417 of sponsor advances were converted to capital, as reflected in the non-controlling interest section of the accompanying Consolidated Statement of Partners' Capital.

During the years ended December 31, 2016 and 2015, the sponsor paid $1,652 and $2,787, respectively, of expenses on behalf of Blair and Whitehall. Such transactions are recognized within the non-controlling interest section of the accompanying Consolidated Statement of Partners' Capital.

13. Unit-Based Compensation

Long-Term Incentive Plan

On August 21, 2012, Hi-Crush GP 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 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, cancelled, 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’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.

F-28

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, 2016	201,521		$	29.03
Granted	184,019		$	6.85
Forfeited	(39,399	)	$	52.53
Outstanding at December 31, 2017	346,141		$	14.56

As of December 31, 2017, total compensation expense not yet recognized related to unvested PPUs was $1,974, with a weighted average remaining service period of 1.6 years. The weighted average grant date fair value per unit for PPUs granted during the years ended December 31, 2017, 2016 and 2015 was $6.85, $15.94 and $37.52, respectively.

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.

	Units		Grant Date Weighted-Average Fair Value per Unit
Outstanding at December 31, 2016	378,260		$	16.40
Vested	(28,080	)	$	25.43
Granted	720,923		$	8.94
Forfeited	(34,511	)	$	16.22
Outstanding at December 31, 2017	1,036,592		$	10.97

As of December 31, 2017, total compensation expense not yet recognized related to unvested TPUs was $7,521, 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, 2017, 2016 and 2015 was $8.94, $12.96 and $34.09, respectively. The total fair value of units vested during the years ended December 31, 2017, 2016 and 2015 was $714, $62 and $42, respectively.

Director Unit Grants

The Partnership issued 29,148, 103,377 and 6,344 common units to certain of its directors during the years ended December 31, 2017, 2016 and 2015, respectively. In January 2018, the Partnership issued 36,109 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 employees 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. 

F-29

HI-CRUSH PARTNERS LP

Notes to Consolidated Financial Statements

(Dollars in thousands, except unit and per unit amounts, or where otherwise noted)

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. With respect to any eligible individuals electing to participate in the Second 2017 UPP who were also participating in the 2017 UPP, any contributions that were made to the 2017 UPP and not withdrawn by a participant before September 14, 2017 were applied to the Second 2017 UPP. 

Based on the current elected contributions, the participants will have the right to purchase an aggregate of approximately 347,000 common units. As of December 31, 2017, total accumulated contributions of $438 from directors under the Second 2017 UPP is maintained within the accrued and other current liabilities line item on our Consolidated Balance Sheet.

Compensation Expense

The following table presents total unit-based compensation expense:

	Year Ended December 31,
	2017		2016		2015
Performance Phantom Units	$	1,549	$	634	$	1,973
Time-Based Phantom Units	3,149		1,359		724
Director and other unit grants	499		474		273
Unit Purchase Programs	517		153		13
Total compensation expense	$	5,714	$	2,620	$	2,983

14. Related Party Transactions

Effective August 16, 2012, our sponsor entered into a services agreement (the "Services Agreement") with our general partner, Hi-Crush Services LLC ("Hi-Crush Services") and the Partnership, pursuant to which Hi-Crush Services provides certain management and administrative services to the Partnership to assist in operating the Partnership’s business. Under the Services Agreement, the Partnership reimburses Hi-Crush Services and its affiliates, on a monthly basis, for the allocable expenses it incurs in its performance under the Services Agreement. These expenses include, among other things, administrative, rent and other expenses for individuals and entities that perform services for the Partnership. Hi-Crush Services and its affiliates will not be liable to the Partnership for its performance of services under the Services Agreement, except for liabilities resulting from gross negligence. During the years ended December 31, 2017, 2016 and 2015, the Partnership incurred $5,521, $4,938 and $5,260, respectively, of management and administrative service expenses from Hi-Crush Services.

In the normal course of business, our sponsor and its affiliates, including Hi-Crush Services, and the Partnership may from time to time make payments on behalf of each other.

As of December 31, 2017 and 2016, an outstanding balance of $12,399 and $118,641, respectively, payable to our sponsor is maintained as a current liability under the caption "Due to sponsor". On March 15, 2017 and August 31, 2016, $116,417 and $120,950, respectively, of sponsor advances were converted into capital. The December 31, 2016 balance was primarily related to construction advances made to Whitehall.

During the year ended December 31, 2015, the Partnership purchased $2,754 of sand from Goose Landing, LLC, a wholly owned subsidiary of Northern Frac Proppants II, LLC, which is reflected in cost of goods sold. During the years ended December 31, 2017 and 2016, the Partnership did not purchase any sand from Goose Landing, LLC. The father of Mr. Alston, who is a director of our general partner, owned a beneficial equity interest in Northern Frac Proppants II, LLC.

F-30

HI-CRUSH PARTNERS LP

Notes to Consolidated Financial Statements

(Dollars in thousands, except unit and per unit amounts, or where otherwise noted)

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. As of December 31, 2017 and 2016, the Partnership purchased $6,593 and $1,566, respectively, of equipment from PropX, which is reflected in property, plant and equipment. As of December 31, 2017 and 2016, the Partnership had accounts payable of $1,273 and $1,553, 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, 2017 and 2016, we incurred $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, 2017, 2016 and 2015, 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 is 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.

15. Impairments and Other Expenses

During the year ended December 31, 2016, the Partnership recognized a $33,745 impairment loss of all goodwill. Our goodwill arose from the acquisition of D&I in 2013 and is therefore allocated to the D&I reporting unit. We performed our annual assessment of the recoverability of goodwill during the third quarter of 2015. As part of the first step of goodwill impairment testing, we updated our assessment of our future cash flows, applying expected long-term growth rates, discount rates, and terminal values that we considered reasonable. We calculated a present value of the cash flows to arrive at an estimate of fair value under the income approach, and then used the market approach to corroborate this value. As a result of these estimates, we determined that there was no impairment of goodwill as of our annual assessment date. In addition, we reviewed and assessed various factors during the fourth quarter of 2015 and we determined that there was no impairment of goodwill as of December 31, 2015.

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.

During the year ended December 31, 2015, we completed an impairment assessment of the intangible asset associated with the Sand Supply Agreement.  Given market conditions, coupled with our ability to internally produce sand on more favorable terms, we determined that the fair value of the agreement was less than its carrying value, resulting in an impairment of $18,606. The Partnership did not recognize any impairments for intangible assets during the years ended December 31, 2017 and 2016.

During the year ended December 31, 2015, we elected to temporarily idle five destination transload facilities and three rail origin transload facilities.  In addition, to consolidate our administrative functions, we closed down a regional office facility. As a result of these actions, we recognized an impairment of $6,186 related to the write down of transload and office facilities’ assets to their net realizable value, and severance, retention and relocation costs of $571 for affected employees. No impairment charges were recorded for long-lived assets during the years ended December 31, 2017 and 2016.

F-31

HI-CRUSH PARTNERS LP

Notes to Consolidated Financial Statements

(Dollars in thousands, except unit and per unit amounts, or where otherwise noted)

We recognized impairments and other expenses as outlined in the following table:

	Year Ended December 31,
	2017		2016		2015
Impairment of Goodwill	$	—	$	33,745	$	—
Impairment of Sand Supply Agreement	—		—		18,606
Impairment of idled administrative and transload facilities	—		—		6,186
Severance, retention and relocation	40		280		571
Exploration expenses	143		—		—
Abandonment of construction projects	460		—		256
Expiration of exclusivity agreements	222		—		40
Impairments and other expenses	$	865	$	34,025	$	25,659

16. 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.

17. 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, 2017, 2016 and 2015:

	Year Ended December 31,
	2017		2016		2015
Customer A	*		*		11	%
Customer B	26	%	28	%	26	%
Customer C	11	%	17	%	12	%
Customer D	*		14	%	*
Customer E	*		19	%	19	%

*  Less than ten percent

Throughout 2017, the Partnership has maintained cash balances in excess of federally insured amounts on deposit with financial institutions.

F-32

HI-CRUSH PARTNERS LP

Notes to Consolidated Financial Statements

(Dollars in thousands, except unit and per unit amounts, or where otherwise noted)

18. Quarterly Financial Data (Unaudited)

As discussed in Note 2 - Basis of Presentation, the Blair 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 Blair for the first and second quarters of 2016 and to include Whitehall and Other Assets for all 2016 periods presented.

2017	First Quarter (a)			Second Quarter			Third Quarter (b)			Fourth Quarter			Total
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	(3,338		)	18,524			32,479			50,384			98,049
Net income (loss)	(6,831		)	16,380			29,807			43,178			82,534
Earnings (loss) per limited partner unit:
Basic	$	(0.07	)	$	0.18		$	0.33		$	0.48		$	0.97
2016
Revenues	$	52,148		$	38,429		$	46,556		$	67,297		$	204,430
Gross profit (loss)	(7		)	(1,262		)	(57		)	416			(910		)
Loss from operations	(48,860		)	(8,088		)	(8,813		)	(5,105		)	(70,866		)
Net loss	(52,500		)	(12,159		)	(11,734		)	(8,126		)	(84,519		)
Loss per limited partner unit:
Basic	$	(1.39	)	$	(0.26	)	$	(0.21	)	$	(0.11	)	$	(1.64	)

(a) The first quarter of 2016 includes a $33,745 impairment of goodwill. Refer to Note 15 for additional disclosure.

(b) The third quarter of 2017 includes $3,554 of other operating income related to a contract dispute that was subsequently resolved.

19. Subsequent Events

On January 17, 2018, our general partner's board of directors declared a cash distribution for the fourth quarter of 2017 totaling $17,809, or $0.20 per common unit. This distribution was paid on February 13, 2018 to unitholders of record on February 1, 2018. No distributions were declared for our holders of incentive distribution rights.

F-33

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, 2017	$	1,549	$	—	$	(489	)	$	1,060
Year Ended December 31, 2016	$	663	$	8,236	$	(7,350	)	$	1,549
Year Ended December 31, 2015	$	984	$	101	$	(422	)	$	663

F-34

EX-21.1

Exhibit 21.1

LIST OF SUBSIDIARIES OF HI-CRUSH PARTNERS LP

Hi-Crush Partners LP, owns, directly or indirectly, 100% of the voting securities of each of the subsidiaries listed below other than Hi-Crush Augusta LLC, of which it owns directly and indirectly 98% of the voting securities.

Name	Jurisdiction
Hi-Crush Operating LLC	Delaware
Hi-Crush Chambers LLC	Delaware
Hi-Crush Wyeville LLC	Delaware
Hi-Crush Railroad LLC	Delaware
D & I Silica, LLC	Pennsylvania
Hi-Crush Finance Corp.	Delaware
Hi-Crush Augusta Acquisition Co. LLC	Delaware
Hi-Crush Augusta LLC	Delaware
Hi-Crush Canada Inc.	Delaware
Hi-Crush Canada Distribution Corp.	Canada
Hi-Crush Blair LLC	Delaware
Hi-Crush Investments Inc.	Delaware
Hi-Crush LMS LLC	Delaware
Hi-Crush PODS LLC	Delaware
Hi-Crush Permian Sand LLC	Delaware
Hi-Crush Whitehall LLC	Delaware
PDQ Properties LLC	Wisconsin

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement Nos. 333-217966 and 333-214888 on Form S-3 and in Registration Statement Nos. 333-215511 and 333-187796 on Form S-8 of our report dated February 19, 2018, relating to the consolidated financial statements and financial statement schedules of Hi-Crush Partners LP, and the effectiveness of Hi-Crush Partners LP's internal control over financial reporting, appearing in this Annual Report on Form 10-K of Hi-Crush Partners LP for the year ended December 31, 2017.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

February 19, 2018

EX-23.2

Exhibit 23.2

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on Form S‑3 (Nos. 333-214888 and 333-217966) and Form S-8 (Nos. 333-187796 and 333-215511) of Hi-Crush Partners LP of our report dated February 21, 2017, except with respect to our opinion on the consolidated financial statements insofar as it relates to the effects of merger of entities under common control discussed in Note 4, as to which the date is May 1, 2017, relating to the financial statements and financial statement schedule, which appears in this Form 10‑K.

/s/PricewaterhouseCoopers LLP

Houston, Texas

February 19, 2018

EX-23.3

Exhibit 23.3

CONSENT OF JOHN T. BOYD COMPANY

The undersigned hereby consents to the references to our firm in the form and context in which they appear in (i) the Annual Report on Form 10-K of Hi-Crush Partners LP for the fiscal year ended December 31, 2017 and (ii) the Quarterly Reports on Form 10-Q of Hi-Crush Partners LP for the fiscal quarters ended March 31, 2018, June 30, 2018 and September 30, 2018. We hereby further consent to the use in such Form 10-K and Form 10-Qs of information contained in our reports setting forth the estimates of reserves as of December 31, 2017. We hereby further consent to the incorporation by reference in the Registration Statement on Forms S-3 (No. 333-217966 and No. 333-214888) and Forms S-8 (No. 333-215511 and No. 333-187796) of Hi-Crush Partners LP of such information.

Respectfully submitted,

JOHN T. BOYD COMPANY

By:/s/ Authorized Person

Name:     Authorized Person

Title:     Authorized Officer

February 14, 2018

EX-31.1

Exhibit 31.1

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

(Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002)

I, Robert E. Rasmus, certify that:

1. I have reviewed this Annual Report on Form 10-K of Hi-Crush Partners LP;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ Robert E. Rasmus

Robert E. Rasmus

Chief Executive Officer

February 20, 2018

EX-31.2

Exhibit 31.2

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER

(Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002)

I, Laura C. Fulton certify that:

1. I have reviewed this Annual Report on Form 10-K of Hi-Crush Partners LP;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ Laura C. Fulton

Laura C. Fulton

Chief Financial Officer

February 20, 2018

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350

(Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002)

In connection with the Annual Report on Form 10-K for the year ended December 31, 2017 of Hi-Crush Partners LP (the "Partnership") as filed with the Securities and Exchange Commission on the date hereof (the "Report") and pursuant to 18. U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, I, Robert E. Rasmus, Chief Executive Officer of the Partnership, certify, that to my knowledge:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

/s/ Robert E. Rasmus

Robert E. Rasmus

Chief Executive Officer

February 20, 2018

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350

(Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002)

In connection with the Annual Report on Form 10-K for the year ended December 31, 2017 of Hi-Crush Partners LP (the "Partnership") as filed with the Securities and Exchange Commission on the date hereof (the "Report") and pursuant to 18. U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, I, Laura C. Fulton, Chief Financial Officer of the Partnership, certify, that to my knowledge:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

/s/ Laura C. Fulton

Laura C. Fulton

Chief Financial Officer

February 20, 2018

EX-95.1

Exhibit 95.1

MINE SAFETY DISCLOSURES

The following disclosures are provided pursuant to Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Act") and Item 104 of Regulation S-K, which requires certain disclosures by companies required to file periodic reports under the Securities Exchange Act of 1934, as amended, that operate mines regulated under the Federal Mine Safety and Health Act of 1977 (the "Mine Act").

Mine Safety Information

Whenever the Federal Mine Safety and Health Administration ("MSHA") believes a violation of the Mine Act, any health or safety standard or any regulation has occurred, it may issue a citation which describes the alleged violation and fixes a time within which the U.S. mining operator must abate the alleged violation. In some situations, such as when MSHA believes that conditions pose a hazard to miners, MSHA may issue an order removing miners from the area of the mine affected by the condition until the alleged hazards are corrected. When MSHA issues a citation or order, it generally proposes a civil penalty, or fine, as a result of the alleged violation, that the operator is ordered to pay. Citations and orders can be contested and appealed, and as part of that process, may be reduced in severity and amount, and are sometimes dismissed. The number of citations, orders and proposed assessments vary depending on the size and type (underground or surface) of the mine as well as by the MSHA inspector(s) assigned.

Mine Safety Data

The following provides additional information about references used in the table below to describe the categories of violations, orders or citations issued by MSHA under the Mine Act:

• Section 104 S&S Citations: Citations received from MSHA under section 104 of the Mine Act for violations of mandatory health or safety standards that could significantly and substantially contribute to the cause and effect of a mine safety or health hazard.

• Section 104(b) Orders: Orders issued by MSHA under section 104(b) of the Mine Act, which represents a failure to abate a citation under section 104(a) within the period of time prescribed by MSHA. This results in an order of immediate withdrawal from the area of the mine affected by the condition until MSHA determines that the violation has been abated.

• Section 104(d) Citations and Orders: Citations and orders issued by MSHA under section 104(d) of the Mine Act for an unwarrantable failure to comply with mandatory health or safety standards.

• Section 110(b)(2) Violations: Flagrant violations issued by MSHA under section 110(b)(2) of the Mine Act.

• Section 107(a) Orders: Orders issued by MSHA under section 107(a) of the Mine Act for situations in which MSHA determined an "imminent danger" (as defined by MSHA) existed.

Pattern or Potential Pattern of Violations

The following provides additional information about references used in the table below to describe elevated pattern of violation enforcement actions taken by MSHA under the Mine Act:

• Pattern of Violations: A pattern of violations of mandatory health or safety standards that are of such nature as could have significantly and substantially contributed to the cause and effect of mine health or safety hazards under section 104(e) of the Mine Act.

• Potential Pattern of Violations: The potential to have a pattern of violations under section 104(e).

Pending Legal Actions

The following provides additional information of the types of proceedings brought before the Federal Mine Safety and Health Review Commission (FMSHRC):

• Contest Proceedings: A contest proceeding may be filed by an operator to challenge the issuance of a citation or order issued by MSHA.

• Civil Penalty Proceedings: A civil penalty proceeding may be filed by an operator to challenge a civil penalty MSHA has proposed for a violation contained in a citation or order. The Partnership does not institute civil penalty proceedings based solely on the assessment amount of proposed penalties. Any initiated adjudications address substantive matters of law and policy instituted on conditions that are alleged to be in violation of mandatory standards of the Mine Act.

• Discrimination Proceedings: Involves a miner’s allegation that he or she has suffered adverse employment action because he or she engaged in activity protected under the Mine Act, such as making a safety complaint. Also includes temporary reinstatement proceedings involving cases in which a miner has filed a complaint with MSHA stating that he or she has suffered discrimination and the miner has lost his or her position.

• Compensation Proceedings: A compensation proceeding may be filed by miners entitled to compensation when a mine is closed by certain closure orders issued by MSHA. The purpose of the proceeding is to determine the amount of compensation, if any, due to miners idled by the orders.

• Temporary Relief: Applications for temporary relief are applications filed under section 105(b)(2) of the Mine Act for temporary relief from any modification or termination of any order.

• Appeals: An appeal may be filed by an operator to challenge judges’ decisions or orders to the Commission, including petitions for discretionary review and review by the Commission on its own motion.

For the year endedDecember 31, 2017:

Mine (a)	Wyeville, WI	Whitehall, WI	Augusta, WI	Blair, WI	Kermit, TX
Section 104 citations for violations of mandatory health or safety standards that could significantly and substantially contribute to the cause and effect of a mine safety or health hazard (#)	—	1	3	2	—
Section 104(b) orders (#)	—	—	—	—	—
Section 104(d) citations and orders (#)	—	—	—	—	—
Section 110(b)(2) violations (#)	—	—	—	—	—
Section 107(a) orders (#)	—	—	—	—	—
Proposed assessments under MSHA (b)	$1,044	$996	$628	$232	$1,276
Mining-related fatalities (#)	—	—	—	—	—
Section 104(e) notice	No	No	No	No	No
Notice of the potential for a pattern of violations under Section 104(e)	No	No	No	No	No
Legal actions before the Federal Mine Safety and Health Review Commission ("FMSHRC") initiated (#)	—	—	—	—	—
Legal actions before the FMSHRC resolved (#)	—	—	—	—	—
Legal actions pending before the FMSHRC, end of period:
Contests of citations and orders referenced in Subpart B of 29 CFR Part 2700 (#)	—	—	—	—	—
Contests of proposed penalties referenced in Subpart C of 29 CFR Part 2700 (#)	—	—	—	—	—
Complaints for compensation referenced in Subpart D of 29 CFR Part 2700 (#)	—	—	—	—	—
Complaints of discharge, discrimination or interference referenced in Subpart E of 29 CFR Part 2700 (#)	—	—	—	—	—
Applications for temporary relief referenced in Subpart F of 29 CFR Part 2700 (#)	—	—	—	—	—
Appeals of judges’ decisions or orders referenced in Subpart H of 29 CFR Part 2700 (#)	—	—	—	—	—
Total pending legal actions (#)	—	—	—	—	—

(a) The definition of mine under section 3 of the Mine Act includes the mine, as well as other items used in, or to be used in, or resulting from, the work of extracting minerals, such as land, structures, facilities, equipment, machines, tools and minerals preparation facilities. Unless otherwise indicated, any of these other items associated with a single mine have been aggregated in the totals for that mine. MSHA assigns an identification number to each mine and may or may not assign separate identification numbers to related facilities such as preparation facilities. We are providing the information in the table by mine rather than MSHA identification number because that is how we manage and operate our mining business and we believe this presentation will be more useful to investors than providing information based on MSHA identification numbers.

(b) Represents the total dollar value of the proposed assessment from MSHA under the Mine Act pursuant to the citations and/or orders preceding such dollar value in the corresponding row.

XML

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2017	Feb. 15, 2018	Jun. 30, 2017
Document And Entity Information [Abstract]
Entity Registrant Name	Hi-Crush Partners LP
Trading Symbol	HCLP
Entity Central Index Key	0001549848
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Document Type	10-K
Document Period End Date	Dec. 31, 2017
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Common Stock, Shares Outstanding		89,130,197
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 887,328,114

XML

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	[1]
Current assets:
Cash	$ 5,662	$ 4,521
Accounts receivable, net (Note 3)	139,448	52,834
Inventories (Note 5)	44,272	29,277
Prepaid expenses and other current assets	2,832	2,716
Total current assets	192,214	89,348
Property, plant and equipment, net (Note 6)	899,158	541,693
Goodwill and intangible assets, net (Note 7)	8,416	10,097
Equity method investments	17,475	10,232
Other assets	5,877	7,831
Total assets	1,123,140	659,201
Current liabilities:
Accounts payable	46,794	19,264
Accrued and other current liabilities (Note 8)	29,931	8,155
Current portion of deferred revenues	4,399	0
Due to sponsor	12,399	118,641
Current portion of long-term debt (Note 9)	2,957	2,962
Total current liabilities	96,480	149,022
Deferred revenues	7,384	0
Long-term debt (Note 9)	194,462	193,458
Asset retirement obligations (Note 10)	10,179	9,514
Other liabilities (Note 11)	19,000	5,000
Total liabilities	327,505	356,994
Commitments and contingencies (Note 11)
Equity and partners' capital:
General partner interest	0	0
Limited partners interest, 89,009,188 and 63,668,244 units outstanding, respectively	795,635	299,516
Total partners' capital	795,635	299,516
Non-controlling interest	0	2,691
Total equity and partners' capital	795,635	302,207
Total liabilities, equity and partners' capital	$ 1,123,140	$ 659,201

[1] Financial information has been recast to include the financial position and results attributable to Hi-Crush Whitehall LLC and Other Assets.

XML

Consolidated Balance Sheets (Parenthetical) - shares	Dec. 31, 2017	Dec. 31, 2016
Statement of Financial Position [Abstract]
Limited partners interest, units outstanding	89,009,188	63,668,244

XML

Consolidated Statements of Operations - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	[1]	Dec. 31, 2015	[1],[2]
Income Statement [Abstract]
Revenues	$ 602,623	$ 204,430		$ 339,640
Cost of goods sold (excluding depreciation, depletion and amortization)	438,348	188,308		239,625
Depreciation, depletion and amortization	29,449	17,032		16,613
Gross profit (loss)	134,826	(910)		83,402
Operating costs and expenses:
General and administrative expenses	39,008	35,501		27,811
Impairments and other expenses (Note 15)	865	34,025		25,659
Accretion of asset retirement obligations (Note 10)	458	430		394
Other operating income	(3,554)	0		(12,310)
Income (loss) from operations	98,049	(70,866)		41,848
Other income (expense):
Earnings from equity method investments	75	0		0
Interest expense	(11,258)	(13,653)		(14,126)
Loss on extinguishment of debt	(4,332)	0		0
Net income (loss)	$ 82,534	$ (84,519)		$ 27,722
Earnings (loss) per limited partner unit:
Earnings (loss) per limited partner unit - basic (usd per unit)	$ 0.97	$ (1.64)		$ 0.73
Earnings (loss) per limited partner unit - diluted (usd per unit)	$ 0.96	$ (1.64)		$ 0.73
Weighted average limited partner units outstanding, basic (in units)	86,518,249	49,567,268		36,958,988
Weighted average limited partner units outstanding, diluted (in units)	87,900,982	49,567,268		37,150,878
Distribution declared per limited partner unit (usd per unit)	$ 0.35	$ 0		$ 1.15

[1] Financial information has been recast to include the financial position and results attributable to Hi-Crush Whitehall LLC and Other Assets.

[2] Financial information has been recast to include the financial position and results attributable to Hi-Crush Blair LLC.

XML

Consolidated Statements of Cash Flows - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015	[2]
Operating activities:
Net income (loss)		$ 82,534	$ (84,519)	[1]	$ 27,722	[1]
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation and depletion		29,456	17,039	[1]	15,684	[1]
Amortization of intangible assets		1,681	1,682	[1]	2,620	[1]
Loss on impairments of goodwill and intangible assets		0	33,745	[1]	18,606	[1]
Provision for doubtful accounts		0	8,236	[1]	0	[1]
Unit-based compensation to directors and employees		5,714	2,620	[1]	2,983	[1]
Amortization of loan origination costs into interest expense		1,391	1,866	[1]	2,293	[1]
Accretion of asset retirement obligations (Note 10)		458	430	[1]	394	[1]
(Gain) loss on disposal or impairments of property, plant and equipment		92	(357)	[1]	6,514	[1]
Earnings from equity method investments		(75)	0	[1]	0	[1]
Loss on extinguishment of debt		4,332	0	[1]	0	[1]
Changes in operating assets and liabilities:
Accounts receivable		(86,614)	(19,593)	[1]	40,640	[1]
Inventories		(14,529)	7,270	[1]	(6,954)	[1]
Prepaid expenses and other current assets		(119)	2,190	[1]	1,561	[1]
Other assets		2,112	1,360	[1]	(2,962)	[1]
Accounts payable		25,354	1,277	[1]	(2,583)	[1]
Accrued and other current liabilities		21,918	(434)	[1]	(6,326)	[1]
Deferred revenues		11,783	0	[1]	0	[1]
Due to sponsor		10,781	(797)	[1]	556	[1]
Net cash provided by (used in) operating activities		96,269	(27,985)	[1]	100,748	[1]
Investing activities:
Capital expenditures for property, plant and equipment		(122,032)	(44,011)	[1]	(127,217)	[1]
Proceeds from sale of property, plant and equipment		8	1,403	[1]	0	[1]
Cash used for business combinations		(140,000)	(75,000)	[1]	0	[1]
Cash paid for asset acquisition		(200,830)	0	[1]	0	[1]
Equity method investments		(7,168)	(10,232)	[1]	0	[1]
Restricted cash, net		0	0	[1]	691	[1]
Net cash used in investing activities		(470,022)	(127,840)	[1]	(126,526)	[1]
Financing activities:
Proceeds from equity issuances, net		412,577	189,037	[1]	0	[1]
Proceeds from issuance of long-term debt		198,000	0	[1]	65,000	[1]
Repayment of long-term debt		(198,151)	(58,396)	[1]	(14,928)	[1]
Loan origination costs		(4,731)	(128)	[1]	(406)	[1]
Affiliate financing, net		456	16,480	[1]	53,512	[1]
Proceeds from participants in unit purchase programs		438	111	[1]	403	[1]
Repurchase of common units		(20,000)	0	[1]	0	[1]
Payment of accrued distribution equivalent rights		(39)	0	[1]	0	[1]
Distributions paid		(13,656)	0	[1]	(70,072)	[1]
Net cash provided by financing activities		374,894	147,104	[1]	33,509	[1]
Net increase (decrease) in cash		1,141	(8,721)	[1]	7,731	[1]
Cash at beginning of period	[1]	4,521	13,242	[2]	5,511
Cash at end of period		5,662	4,521	[1]	13,242	[1]
Non-cash investing and financing activities:
Increase (decrease) in accounts payable and accrued liabilities for additions to property, plant and equipment		2,176	(8,125)	[1]	1,141	[1]
Increase in property, plant and equipment for asset retirement obligations		207	373	[1]	0	[1]
Debt financed capital expenditures		0	3,676	[1]	3,676	[1]
Estimated fair value of contingent consideration liability		14,000	5,000	[1]	0	[1]
Issuance of units for asset acquisition		62,242	0	[1]	0	[1]
Issuance of units under unit purchase programs		1,576	0	[1]	0	[1]
Increase (decrease) in accrued distribution equivalent rights		45	(88)	[1]	245	[1]
Due to sponsor balance converted into non-controlling interest		116,417	120,950	[1]	0	[1]
Expense paid by sponsor on behalf of the Partnership		0	1,652	[1]	2,787	[1]
Cash paid for interest		$ 9,867	$ 11,787	[1]	$ 11,833	[1]

[1] Financial information has been recast to include the financial position and results attributable to Hi-Crush Whitehall LLC and Other Assets.

[2] Financial information has been recast to include the financial position and results attributable to Hi-Crush Blair LLC.

XML

Consolidated Statements of Partners' Capital - USD ($) $ in Thousands		Total		General Partner Capital	Limited Partner Capital	Limited Partner Capital Common Units	Limited Partner Capital Sponsor Subordinated Units	Total Partner Capital	Noncontrolling Interest
Partners' Capital, beginning balance at Dec. 31, 2014		$ 189,298			$ 186,425	$ 190,597	$ (4,172)	$ 186,425	$ 2,873
Increase (Decrease) in Partners' Capital
Issuance of common units to directors and employees		200			200	200		200
Conversion into common units	[1]	0				(21,393)	21,393
Allocation of recast net income (loss) for subordinated units capital	[2]	0				5,501	(5,501)
Unit-based compensation expense		2,710			2,710	2,710		2,710
Distributions, including distribution equivalent rights		(70,317)		$ (2,622)	(67,695)	(42,802)	(24,893)	(70,317)
Non-cash contributions by sponsor	[1]	2,787	[2]						2,787
Net income (loss)	[1],[2]	27,722		2,622	25,100	11,927	13,173	27,722	0
Partners' Capital, ending balance at Dec. 31, 2015		152,400		0	146,740	146,740	0	146,740	5,660
Increase (Decrease) in Partners' Capital
Issuance of common units, net		189,037			189,037	189,037		189,037
Issuance of common units to directors and employees		453			453	453		453
Unit-based compensation expense		2,146			2,146	2,146		2,146
Forfeiture of distribution equivalent rights		88			88	88		88
Non-cash contributions by sponsor	[2]	1,652							1,652
Conversion of advances to Hi-Crush Proppants LLC		120,950							120,950
Acquisition of business		(80,000)			45,571	45,571		45,571	(125,571)
Net income (loss)	[2]	(84,519)		0	(84,519)	(84,519)	0	(84,519)	0
Partners' Capital, ending balance at Dec. 31, 2016		302,207	[2]	0	299,516	299,516	0	299,516	2,691
Increase (Decrease) in Partners' Capital
Issuance of common units, net		412,577			412,577	412,577		412,577
Issuance of common units for asset acquisition		62,242			62,242	62,242		62,242
Issuance of common units to directors and employees		2,144			2,144	2,144		2,144
Repurchase of common units		(20,000)			(20,000)	(20,000)		(20,000)
Unit-based compensation expense		5,215			5,215	5,215		5,215
Distributions, including distribution equivalent rights		(13,808)		0	(13,808)	(13,808)	0	(13,808)
Forfeiture of distribution equivalent rights		107			107	107		107
Non-cash contributions by sponsor		0
Conversion of advances to Hi-Crush Proppants LLC		116,417							116,417
Acquisition of business		(154,000)			(34,892)	(34,892)		(34,892)	(119,108)
Net income (loss)		82,534		0	82,534	82,534	0	82,534	0
Partners' Capital, ending balance at Dec. 31, 2017		$ 795,635		$ 0	$ 795,635	$ 795,635	$ 0	$ 795,635	$ 0

[1] Financial information has been recast to include the financial position and results attributable to Hi-Crush Blair LLC.

[2] Financial information has been recast to include the financial position and results attributable to Hi-Crush Whitehall LLC and Other Assets.

XML

Consolidated Statements of Partners' Capital (Parenthetical) - shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Statement of Partners' Capital [Abstract]
Number of common units issued to directors and employees (in units)	329,238	103,377	6,344
Number of common units issued (in units)	23,575,000	19,550,000
Number of common units issued for an asset acquisition (in units)	3,438,789
Number of common units repurchased (in units)	2,030,163

XML

Business and Organization

12 Months Ended

Dec. 31, 2017

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Business and Organization

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" or "Hi-Crush GP"), and a 100% limited partner interest to Hi-Crush Proppants LLC (the "sponsor"), its organizational limited partner. The Partnership is a premier provider of proppant and logistics solutions to the North American energy industry. Our portfolio of production facilities produces high-quality monocrystalline sand, a specialized mineral used as a proppant during the well completion process, necessary to facilitate the recovery of hydrocarbons from oil and natural gas wells. Our Wisconsin production facilities' have direct access to major U.S. railroads and our strategically located owned and operated in-basin terminals as well as our Texas production facility positions us within close proximity to significant activity in all major oil and gas basins. Our integrated distribution system, including our PropStream^TM logistics service, delivers proppant the "last mile" into the blender.

On January 31, 2013 and April 8, 2014, the Partnership entered into agreements with the sponsor which ultimately resulted in the acquisition of 98.0% of the common equity interests in Hi-Crush Augusta LLC ("Augusta"), the entity that owned the sponsor’s Augusta raw frac sand processing facility.

On June 10, 2013, the Partnership acquired an independent frac sand supplier, D & I Silica, LLC ("D&I"), transforming the Partnership into an integrated Northern White frac sand producer, transporter, marketer and distributor. Founded in 2006, D&I was the largest independent frac sand supplier to the oil and gas industry drilling in the Marcellus and Utica shale plays.

On August 9, 2016, the Partnership entered into a contribution agreement with the sponsor to acquire all of the outstanding membership interests in Hi-Crush Blair LLC ("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 "Blair Contribution"). The Partnership completed the acquisition of the Blair facility on August 31, 2016.

On February 23, 2017, the Partnership entered into a contribution agreement with our sponsor to acquire 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 Augusta, and all of the outstanding membership interests in PDQ Properties LLC (together, the "Other Assets"), for $140,000 in cash and up to $65,000 of contingent consideration over a two-year period (the "Whitehall Contribution"). The Partnership completed this acquisition on March 15, 2017.

On March 3, 2017, the Partnership completed an acquisition of Permian Basin Sand Company, LLC ("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. 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, within 75 miles of significant Delaware and Midland Basin activity.

XML

Basis of Presentation

12 Months Ended

Dec. 31, 2017

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of Presentation

Basis of Presentation

The Blair Contribution and Whitehall Contribution were accounted for as transactions between entities under common control whereby the net assets of Blair, Whitehall and Other Assets were recorded at their historical cost. Therefore, the Partnership's historical financial information has been recast to combine 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 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.

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Significant Accounting Policies

12 Months Ended

Dec. 31, 2017

Accounting Policies [Abstract]

Significant Accounting Policies

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 raw 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 December 31, 2017 and 2016, the Partnership maintained an allowance for doubtful accounts of $1,060 and $1,549, respectively. 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.

Deferred 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 $1,391, $1,866 and $2,293 for the years ended December 31, 2017, 2016 and 2015, respectively.

On December 22, 2017, the Partnership replaced our amended and restated credit agreement (the "Prior Revolving Credit Agreement") and our 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.

On April 28, 2016 and November 5, 2015, we amended our Prior Revolving Credit Agreement. As a result of these modifications, we accelerated amortization of $349 and $662, respectively, representing a portion of the remaining unamortized balance of debt issuance costs, which is included in interest expense.

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. In connection with the refinancing in December 2017, the Partnership incurred debt issuance costs of $4,731 that were capitalized. As of December 31, 2017 and 2016, the Partnership maintained unamortized debt issuance costs of $3,643 and $3,538 within long-term debt, respectively and $1,070 and $913 within other assets, respectively. Balances maintained in other assets represent costs associated with our revolving credit facility. Refer to Note 9 - Long-Term Debt for additional disclosure on our Revolving Credit Agreement and Term Loan Credit Facility.

The following is a summary of future amortization expense associated with deferred charges:

For the years ending December 31,
2018	$	673
2019	673
2020	673
2021	673
2022	673
Thereafter	1,348
Total	$	4,713

Inventories

Sand inventory is stated at the lower of cost or net realizable value using the average cost method.

Inventory manufactured at our plant 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.

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 line in the 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.

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.

During the year ended December 31, 2015, we elected to idle five destination transload facilities and three rail origin transload facilities.  In addition, to consolidate our administrative functions, we closed down a regional office facility. As a result of these actions, we recognized an impairment of $6,186 related to the write-down of transload and office facilities assets to their net realizable value. No impairment charges were recorded during the years ended December 31, 2017 and 2016. Refer to Note 15 - Impairments and Other Expenses for additional disclosure regarding impairments.

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 all goodwill. Refer to Note 15 - Impairments and Other 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. During the year ended December 31, 2015, we completed an impairment assessment of the intangible asset associated with a third party supply agreement (the "Sand Supply Agreement").  Given market conditions, coupled with our ability to internally produce sand on more favorable terms, we determined that the fair value of the agreement was less than its carrying value, resulting in an impairment of $18,606. The Partnership did not recognize any impairments for intangible assets during the years ended December 31, 2017 and 2016. Refer to Note 15 - Impairments and Other Expenses for additional disclosure regarding impairments.

Equity Method Investments

The Partnership accounts for investments, which 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.

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. As of December 31, 2017, the Partnership's investment basis in PropX was $17,475, which is accounted for as an equity method investment as the Partnership has a non-controlling interest in PropX, but has the ability to exercise significant influence. During the years ended December 31, 2017 and 2016, the Partnership made capital contributions of $7,168 and $10,232, respectively, to PropX. During the year ended December 31, 2017, we recognized earnings of $75 from our proportionate share of PropX's operating results. During the year ended December 31, 2016, we did not recognize any earnings from our proportionate share of PropX's operating results.

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.  In connection with its recent acquisitions of Blair and Whitehall and Other Assets from its sponsor, the Partnership has entered into certain contingent consideration arrangements.  As such transactions are between entities under common control, any differences between the calculated fair value, and the actual resulting payments in the future will be 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

Frac sand sales revenues are recognized when legal title passes to the customer, which may occur at the production facility, rail origin, terminal or wellsite. At that point, delivery has occurred, evidence of a contractual arrangement exists and collectability is reasonably assured. Amounts received from customers in advance of sand deliveries are recorded as deferred revenue. As of December 31, 2017, the Partnership has recorded a total liability of $11,783 for prepayments of future deliveries of frac sand. These prepayments are refundable in the event that the Partnership is unable to meet the minimum sand volumes required under the contract.

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 2018 and 2024. The agreements define, among other commitments, the volume of product that the Partnership must provide, the price that will be charged to the customer, and the volume that the customer must purchase by the end of the defined cure periods, which can range from three months to the end of a contract year.

Revenue from make-whole provisions in our customer contracts is recognized at the end of the defined cure period when collectability is certain. Customer prepayments in excess of customer obligations remaining on account upon the termination of a contract are recognized as other operating income during the period in which the 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. During the year ended December 31, 2015, the Partnership recognized $12,310 as part of a settlement payment for past and future obligations under a customer contract, which is included in other operating income on our Consolidated Statements of Operations.

Transportation services revenues are recognized as the services have been completed, meaning the related services have been rendered. At that point, delivery of service has occurred, evidence of a contractual arrangement exists and collectability is reasonably assured.

Fair Value of Financial Instruments

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 fair value of the senior secured term loan approximated $198,015 as of December 31, 2017, based on the market price quoted from external sources, compared with a carrying value of $200,000. If the senior secured term loan was measured at fair value in the financial statements, it would be classified as Level 2 in the fair value hierarchy.

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.

As described in Note 2 - Basis of Presentation, the Partnership's historical financial information has been recast to consolidate Blair, Whitehall and Other Assets for all periods presented. The amounts of incremental income or losses recast to periods prior to the 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, 2017 and 2016, the Partnership did not have any liabilities for uncertain tax positions or gross unrecognized tax benefits.

Recent Accounting Pronouncements

In May 2017, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update No. 2017-09 ("ASU 2017-09"), Compensation - Stock Compensation (Topic 718): Scope of Modification Accounting. This update provides guidance about which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting in Topic 718. The amendments in this update will be applied prospectively to an award modified on or after the adoption date. ASU 2017-09 is effective for the Partnership beginning after December 15, 2017, with early adoption permitted. The Partnership is currently assessing the impact that adopting this new accounting guidance will have on its Consolidated Financial Statements and footnote disclosures.

In January 2017, the FASB issued Accounting Standards Update No. 2017-03 ("ASU 2017-03"), Accounting Changes and Error Corrections (Topic 250) and Investments-Equity Method and Joint Ventures (Topic 323): Amendments to SEC Paragraphs Pursuant to Staff Announcements at the September 22, 2016 and November 17, 2016 EITF Meetings. This update adds language to the SEC Staff Guidance in relation to ASU 2014-09, ASU 2016-02, and ASU 2016-13. This ASU 2017-03 provides the SEC Staff view that a registrant should consider additional quantitative and qualitative disclosures related to the previously mentioned ASUs in connection with the status and impact of their adoption. This guidance, which was effective immediately, did not have a material impact on our Consolidated Financial Statements.

In January 2017, the FASB issued Accounting Standards Update No. 2017-01 ("ASU 2017-01"), Business Combinations (Topic 805): Clarifying the Definition of a Business. This update clarifies the definition of a business and provides additional guidance for determining whether transactions should be accounted for as acquisitions of assets or business. The amendment was effective for the Partnership beginning January 1, 2018, with early adoption permitted, and should be applied prospectively. The Partnership is currently assessing the impact that adopting this new accounting guidance will have on its Consolidated Financial Statements and footnote disclosures, but does not anticipate that adoption will have a material impact on its financial position, results of operations or cash flows.

In February 2016, the FASB issued Accounting Standards Update No. 2016-02 ("ASU 2016-02"), Leases (Topic 842). This update will impact all leases with durations greater than twelve months. In general, such arrangements will be 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 will be recorded for all leases, whether operating or financing, while the statement of operations will reflect 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 will be calculated using the applicable incremental borrowing rate at the date of adoption. The new accounting guidance is effective for the Partnership beginning in the first quarter of 2019, and should be applied retrospectively. The FASB has also issued the following standard which clarifies ASU 2016-02 and has 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). The Partnership is currently assessing the impact that adopting this new accounting guidance will have on its Consolidated Financial Statements and footnote disclosures.

In May 2014, the FASB issued Accounting Standards Update No. 2014-09 ("ASU 2014-09"), Revenue from Contracts with Customers (Topic 606). This update supersedes the most current revenue recognition guidance, as well as some cost recognition guidance. The update requires that an entity recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This update also requires new qualitative and quantitative disclosures about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts, including significant judgments and changes in judgments, information about contract balances and performance obligations, and assets recognized from costs incurred to obtain or fulfill a contract. The authoritative guidance, which may be applied on a full retrospective or modified retrospective basis whereby the entity records a cumulative effect of initially applying this update at the date of initial application, was effective for the Partnership beginning January 1, 2018. The FASB has also issued the following standards which clarify ASU 2014-09 and have the same effective date as the original standard: ASU 2016-12, Revenue from Contracts with Customers: Narrow- Scope Improvements and Practical Expedients, ASU 2016-10 Revenue from Contracts with Customers: Identifying Performance Obligations and Licensing and ASU 2017-13, Revenue Recognition (Topic 605), Revenue from Contracts with Customers (Topic 606), Leases (Topic 840), and Leases (Topic 842).

The Partnership has completed its assessment of the impacts of the adoption of ASU 2014-09. We adopted ASU 2014-09 on January 1, 2018, using the full retrospective approach and it will be fully presented in the Partnership’s Quarterly Report on Form 10-Q for the three months ended March 31, 2018. We finalized the documentation on our assessment of our contracts and determined that there is no impact on our revenue recognition practices or impact to our Consolidated Financial Statements. The adoption of ASU 2014-09 will also result in additional disclosures regarding revenue recognition, disaggregation of revenue types and deferred revenue contract liabilities. The Partnership generates revenue by excavating, processing and delivering frac sand and providing related services and recognizes revenue at the point of delivery to customers or completion of services, at which point the earnings process is deemed to be complete. Amounts received from customers in advance of sand deliveries are recorded as deferred revenue.

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Acquisitions

12 Months Ended

Dec. 31, 2017

Business Combinations [Abstract]

Acquisitions

Acquisitions

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. With the acquisition of Permian Basin Sand, we acquired 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.

The contingent consideration is 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. If those annual thresholds are met, the Partnership will pay an additional $20,000 for each threshold met or exceeded. The Partnership anticipates payment of $20,000 of contingent consideration with respect to the 2017 measurement period in March 2018 to our sponsor pending approval from the conflicts committee. If the Partnership exceeds a total threshold for the cumulative two-year period, then it will pay an additional $25,000, for an undiscounted total of up to $65,000 to be paid in cash or common units at the Partnership's discretion. 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, as reflected in other liabilities on our Consolidated Balance Sheet. Refer to Note 11 - Commitments and Contingencies for additional disclosure regarding the contingent consideration.

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. Any material transactions between the Partnership, Whitehall and Other Assets have been eliminated. The balance of non-controlling interest as of December 31, 2016 includes the sponsor's interest in Whitehall and Other Assets prior to the combination. Except for the combination of the Consolidated Statements of Operations and the respective allocation of recast net income (loss), capital transactions between the sponsor and Whitehall and Other Assets prior to March 15, 2017 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 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 liabilities 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 payable in the future.

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 is based on the Partnership's Adjusted EBITDA exceeding certain thresholds for each of the fiscal years ending December 31, 2017 and 2018. If the Partnership exceeds either or both of the respective thresholds, then it will pay an additional $5,000 for each threshold met or exceeded, for an undiscounted total of up to $10,000. The Partnership anticipates payment of $5,000 of contingent consideration with respect to the 2017 measurement period in March 2018 to our sponsor pending approval from the conflicts committee. 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, as reflected in other liabilities on our Consolidated Balance Sheet. Refer to Note 11 - Commitments and Contingencies for additional disclosure regarding the contingent consideration.

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. Any material transactions between the Partnership and Blair have been eliminated. The balance of non-controlling interest as of December 31, 2016 includes the sponsor's interest in Blair prior to the combination. Except for the combination of the Consolidated Statements of Operations and the respective allocation of recast net income (loss), capital transactions between the sponsor and Blair prior to August 31, 2016 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 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 liabilities 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 payable in the future.

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 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, 2017
	Partnership Historical		Whitehall and Other Assets through  March 15, 2017			Eliminations			Partnership Recast (Supplemental)
Revenues	$	602,623	$	—		$	—		$	602,623
Net income (loss)	$	83,979	$	(1,366	)	$	(79	)	$	82,534
Net income (loss) attributable to Hi-Crush Partners LP	$	84,005	$	(1,392	)	$	(79	)	$	82,534
Net income per limited partner unit - basic	$	0.97							$	0.95

	Year Ended December 31, 2016
	Partnership Historical			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	)	$	716	$	(3,778	)	$	(45	)	$	(84,519	)
Net income (loss) attributable to Hi-Crush Partners LP	$	(81,313	)	$	716	$	(3,877	)	$	(45	)	$	(84,519	)
Net loss per limited partner unit - basic	$	(1.64	)									$	(1.71	)

	Year Ended December 31, 2015
	Partnership Historical		Blair			Whitehall and Other Assets		Eliminations			Partnership Recast (Supplemental)
Revenues	$	339,640	$	—		$	33,217	$	(33,217	)	$	339,640
Net income (loss)	$	28,410	$	(2,619	)	$	1,645	$	286		$	27,722
Net income (loss) attributable to Hi-Crush Partners LP	$	28,265	$	(2,619	)	$	1,790	$	286		$	27,722
Net income per limited partner unit - basic	$	0.73									$	0.71

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Inventories

12 Months Ended

Dec. 31, 2017

Inventory Disclosure [Abstract]

Inventories

Inventories

Inventories consisted of the following:

	December 31,
	2017		2016
Raw material	$	498	$	—
Work-in-process	18,739		17,836
Finished goods	22,892		9,416
Spare parts	2,143		2,025
Inventories	$	44,272	$	29,277

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Property, Plant and Equipment

12 Months Ended

Dec. 31, 2017

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

Property, Plant and Equipment

Property, plant and equipment consisted of the following:

	December 31,
	2017			2016
Buildings	$	21,532		$	16,929
Mining property and mine development	381,653			113,169
Plant and equipment	389,197			331,165
Rail and rail equipment	55,783			56,369
Transload facilities and equipment	121,522			78,105
Construction-in-progress	14,454			1,695
Property, plant and equipment	984,141			597,432
Less: Accumulated depreciation and depletion	(84,983		)	(55,739		)
Property, plant and equipment, net	$	899,158		$	541,693

Depreciation and depletion expense was $29,456, $17,039 and $15,684 for the years ended December 31, 2017, 2016 and 2015, respectively.

The Partnership recognized a (gain) loss on the disposal of fixed assets of $92, $(357) and $72 during the years ended December 31, 2017, 2016 and 2015, respectively, which are included in general and administrative expenses on our Consolidated Statements of Operations.

During the year ended December 31, 2016, the Partnership entered into an agreement to terminate certain existing royalty obligations for $6,750, of which $3,375 was paid during each of September 2017 and 2016. As a result of this agreement, the Partnership reduced its ongoing future royalty payments to the applicable counterparties for each ton of frac sand that is excavated, processed and sold to the Partnership’s customers. As of part of this transaction, we recorded an asset of $6,750, as reflected in property, plant and equipment on the Consolidated Balance Sheet.

As a result of market conditions, the Augusta facility was temporarily idled from October 2015 through September 2016 and the Whitehall facility was temporarily idled during the second quarter of 2016 and resumed operations in March 2017. No impairments were recorded related to the Augusta and Whitehall facilities.

During the year ended December 31, 2015, the Partnership recognized an impairment of $6,186 related to the write-down of transload and office facilities assets to their net realizable value and recognized expense of $256 related to the abandonment of certain transload construction projects. These expenses are included in impairments and other expenses in our Consolidated Statements of Operations. Refer to Note 15 - Impairments and Other Expenses for additional disclosure regarding impairments.

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Goodwill and Intangible Assets

12 Months Ended

Dec. 31, 2017

Goodwill and Intangible Assets Disclosure [Abstract]

Goodwill and Intangible Assets

Goodwill and Intangible Assets

Changes in goodwill and intangible assets consisted of the following:

	Goodwill			Intangible Assets
Balance at December 31, 2015	$	33,745		$	11,779
Loss on impairment (Note 15)	(33,745		)	—
Amortization expense	—			(1,682		)
Balance at December 31, 2016	—			10,097
Amortization expense	—			(1,681		)
Balance at December 31, 2017	$	—		$	8,416

Goodwill

During the year ended December 31, 2016, the Partnership recognized a $33,745 impairment loss of all goodwill that was allocated from the purchase price of its acquisition of D&I in 2013. Refer to Note 15 - Impairments and Other Expenses for additional disclosure regarding our goodwill impairment assessment.

Intangible Assets

Intangible assets arising from the acquisition of D&I consisted of the following:

		December 31,
	Useful life	2017			2016
Supplier agreements	1-20 Years	$	21,997		$	21,997
Customer contracts and relationships	1-10 Years	18,132			18,132
Other intangible assets	1-3 Years	1,749			1,749
Intangible assets		41,878			41,878
Less: Accumulated amortization and impairments		(33,462		)	(31,781		)
Intangible assets, net		$	8,416		$	10,097

Amortization expense was $1,681 and $1,682 for the years ended December 31, 2017 and 2016, respectively. As of December 31, 2017, the unamortized balance of intangible assets is associated with our customer relationships. The weighted average remaining life of intangible assets was 5 years as of December 31, 2017.

During the year ended December 31, 2015, we completed an impairment assessment of the intangible asset associated with the Sand Supply Agreement.  Given current market conditions, coupled with our ability to internally produce sand on more favorable terms, we determined that the fair value of the agreement was less than its carrying value, resulting in an impairment of $18,606. The Partnership did not recognize any impairments for intangible assets during the years ended December 31, 2017 and 2016, respectively. Refer to Note 15 - Impairments and Other Expenses for additional disclosure regarding impairments.

As of December 31, 2017, future amortization is as follows:

Fiscal Year	Amortization
2018	$	1,682
2019	1,682
2020	1,682
2021	1,682
2022	1,682
Thereafter	6
	$	8,416

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Accrued and Other Current Liabilities

12 Months Ended

Dec. 31, 2017

Payables and Accruals [Abstract]

Accrued and Other Current Liabilities

Accrued and Other Current Liabilities

Accrued and other current liabilities consisted of the following:

	December 31,
	2017		2016
Accrued royalty payments	$	8,763	$	3,436
Accrued logistics costs	5,878		763
Accrued compensation and benefits	7,150		1,833
Accrued taxes payable	5,139		389
Accrued interest payable	505		339
Other current liabilities	2,496		1,395
Accrued and other current liabilities	$	29,931	$	8,155

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Long-Term Debt

12 Months Ended

Dec. 31, 2017

Debt Disclosure [Abstract]

Long-Term Debt

Long-Term Debt

Long-term debt consisted of the following:

	December 31,
	2017			2016
Revolving Credit Agreement	$	—		$	—
Prior Revolving Credit Agreement	—			—
Term Loan Credit Facility	200,000			—
Prior Term Loan Credit Facility	—			194,500
Less: Unamortized original issue discount	(1,992		)	(1,247		)
Less: Unamortized debt issuance costs	(3,643		)	(3,538		)
Other notes payable	3,054			6,705
Total debt	197,419			196,420
Less: current portion of long-term debt	(2,957		)	(2,962		)
Long-term debt	$	194,462		$	193,458

Revolving Credit Agreement

On April 28, 2014, the Partnership entered into a five-year amended and restated credit agreement (the "Prior Revolving Credit Agreement"). On August 31, 2016, the Partnership entered into a fourth amendment to the Prior Revolving Credit Agreement, which allowed for the Blair Contribution. On March 3, 2017, the Partnership entered into a fifth amendment to the Prior Revolving Credit Agreement, which allowed for the Whitehall Contribution and the acquisition of Permian Basin Sand. On October 12, 2017, the Partnership entered into a sixth amendment to the Prior Revolving Credit Agreement, which allowed the Partnership to make repurchases of common units up to $20,000. The Prior Revolving Credit Agreement, as amended, was a senior secured revolving credit facility that permitted aggregate borrowings of up to $75,000, including a $25,000 sublimit for letters of credit and a $10,000 sublimit for swing line loans. The outstanding balance under the Prior Revolving Credit Agreement was paid in full during the second quarter of 2016.

On December 22, 2017, the Partnership replaced the Prior Revolving Credit Agreement by entering into a second amended and restated credit agreement (the "Revolving Credit Agreement"), which matures on December 22, 2022. As of December 31, 2017, the Revolving Credit Agreement, as amended, is a senior secured revolving credit facility that permits aggregate borrowings of up to $125,000, including a $30,000 sublimit for letters of credit and a $10,000 sublimit for swing line loans.

As of December 31, 2017, we had $104,334 of undrawn borrowing capacity ($125,000, net of $20,666 letter of credit commitments) and no indebtedness under our Revolving Credit Agreement.

Borrowings under the Revolving Credit Agreement, as amended, bear interest at a rate equal to, at the Partnership's option, either (1) a base rate plus an applicable margin ranging between 1.50% per annum and 2.25% per annum, based upon the Partnership's leverage ratio, or (2) a Eurodollar rate plus an applicable margin ranging between 2.50% per annum and 3.25% per annum, based upon the Partnership's leverage ratio.

The Revolving Credit Agreement 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. The Revolving Credit Agreement requires compliance with customary financial covenants, which are a maximum leverage ratio of 3.25x, a minimum interest coverage ratio of 2.5x and an asset coverage ratio of 1.5x. The Revolving Credit Agreement generally permits repurchases of common units.

As of December 31, 2017, we are in compliance with the covenants contained in the Revolving Credit Agreement. Our ability to comply with such covenants in the future, and access our undrawn borrowing capacity under our Revolving Credit Agreement, is dependent primarily on achieving certain levels of EBITDA, as defined. The Revolving Credit Agreement provides for an "equity cure" that can be applied to EBITDA covenant ratios. Refer to Note 12 - Equity for information regarding our equity distribution program.

The Revolving Credit Agreement contains customary events of default (some of which are subject to applicable grace or cure periods), including among other things, non-payment defaults, covenant defaults, cross-defaults to other material indebtedness, bankruptcy and insolvency defaults, and material judgment defaults. Such events of default could entitle the lenders to cause any or all of the Partnership’s indebtedness under the Revolving Credit Agreement to become immediately due and payable. If such a default were to occur, and resulted in a cross default of the Term Loan Credit Agreement, as described below, all of our outstanding debt obligations could be accelerated which would have a material adverse impact on the Partnership.

The Revolving Credit Agreement is secured by substantially all assets of the Partnership. In addition, the Partnership's subsidiaries have guaranteed the Partnership's obligations under the Revolving Credit Agreement and have granted to the revolving lenders security interests in substantially all of their respective assets.

Term Loan Credit Facility

On April 28, 2014, the Partnership entered into a credit agreement (the "Prior Term Loan Credit Agreement") providing for a seven-year senior secured term loan credit facility (the "Prior Term Loan Credit Facility") that permits aggregate borrowings of up to $200,000, which was fully drawn on April 28, 2014. On December 22, 2017, the outstanding balance under the Prior Term Loan Credit Facility was paid in full.

On December 22, 2017, the Partnership replaced the Prior Term Loan Credit Agreement by entering into an amended and restated credit agreement (the "Term Loan 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. The Term Loan Credit Agreement permits the Partnership, at its option, to add one or more incremental term loan facilities in an aggregate amount not to exceed $100,000. Any incremental term loan facility would be on terms to be agreed among the Partnership, the administrative agent and the lenders who agree to participate in the incremental facility. The maturity date of the Term Loan Credit Facility is December 22, 2024.

The Term Loan Credit Agreement is secured by substantially all assets of the Partnership. In addition, the Partnership’s subsidiaries have guaranteed the Partnership’s obligations under the Term Loan Credit Agreement and have granted to the lenders security interests in substantially all of their respective assets.

Borrowings under the Term Loan Credit Agreement bear interest at a rate equal to, at the Partnership’s option, either (1) a base rate plus an applicable margin of 2.75% per annum or (2) a Eurodollar rate plus an applicable margin of 3.75% per annum, subject to a LIBOR floor of 1.00%. Both base rate loans and Eurodollar loans are subject to a 0.25% rate increase during any period of time in which the Partnership does not have a public company family rating of B2 or better from Moody's Investors Service Inc. ("Moody's"). As of February 15, 2018, the credit rating of the Partnership’s senior secured term loan credit facility was B3 from Moody’s and B- from Standard and Poor’s.

The Term Loan Credit Agreement 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 addition, it contains customary events of default that entitle the lenders to cause any or all of the Partnership’s indebtedness under the Term Loan Credit Agreement 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, 2017, we were in compliance with the terms of the agreement.

As of December 31, 2017, we had $194,365 indebtedness ($200,000, net of $1,992 of discounts and $3,643 of debt issuance costs) under our Term Loan Credit Facility, which carried an interest rate of 5.41%.

Other Notes Payable

On October 24, 2014, the Partnership entered into a purchase and sales agreement to acquire land and underlying frac sand deposits. During the years ended December 31, 2016, 2015 and 2014, the Partnership paid cash consideration of $2,500, and issued a three-year promissory note in the amount of $3,676, respectively, in connection with this agreement. 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 in December 2019, December 2018 and October 2017. 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.

During the years ended December 31, 2017 and 2016, the Partnership made prepayments of $3,651 and $3,896, respectively, based on the accumulated volume of sand extracted, delivered, sold and paid for. In January 2018, the Partnership made a prepayment of $957 based on the volume of sand extracted, delivered, sold and paid for through the fourth quarter of 2017. As of December 31, 2017, the Partnership had repaid in full the promissory note due in October 2017 and December 2018 and we had $3,054 outstanding on our remaining promissory note, which carried interest rate of 0.74%.

Maturities

As of December 31, 2017, future minimum debt repayments, excluding original issue discount and debt issuance costs, are as follows:

Fiscal Year	Amount
2018	$	2,957
2019	4,097
2020	2,000
2021	2,000
2022	2,000
Thereafter	190,000
	$	203,054

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Asset Retirement Obligations

12 Months Ended

Dec. 31, 2017

Asset Retirement Obligation [Abstract]

Asset Retirement Obligations

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, 2014	$	8,317
Accretion expense	394
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

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2017

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

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, 2017, no payments for non-delivery of minimum annual sand volumes have been made by the Partnership to customers under these contracts.

Supplier Contracts

D&I has entered into a long-term supply agreement with a supplier (the "Sand Supply Agreement"), which includes a requirement to purchase certain volumes and grades of sands at specified prices. The quantities set forth in such agreement are not in excess of our current requirements.

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 $19,091, $6,725 and $13,660 for the years ended December 31, 2017, 2016 and 2015, 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 day time frame, we are obligated to purchase the property for fair market value.

As of December 31, 2017, 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, 2017, the Partnership has paid $2,188 under these guarantees.

Lease Obligations

The Partnership has long-term leases for railcars, equipment and certain of its terminals. Railcar rental expense was $27,410, $28,597 and $22,027 for the years ended December 31, 2017, 2016 and 2015, 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 $1,577 and $124 for the years ended December 31, 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. However, the minimum quantities set forth in the agreements are not in excess of our current forecasted requirements at these locations.

As of December 31, 2017, future minimum operating lease payments and minimum purchase commitments are as follows:

Fiscal Year	Operating Leases		Minimum Purchase Commitments
2018	$	33,787	$	5,571
2019	33,638		2,616
2020	30,831		2,296
2021	24,068		2,296
2022	18,036		2,296
Thereafter	16,670		1,871
	$	157,030	$	16,946

In addition, the Partnership has placed orders for additional leased railcars. Such long-term operating leases commence upon the future delivery of 700 railcars, which are scheduled to be delivered during the first half of 2018.

Equity Method Investments

On September 8, 2016, the Partnership committed to investing up to $17,400 in PropX over the next year to 18 months for use in the manufacturing of containers and conveyor systems, among other things. As of December 31, 2017, the Partnership has funded all of its commitment to PropX, of which $7,168 was funded during the year ended December 31, 2017.

Contingent Consideration

As described in Note 4 - Acquisitions, the Partnership may pay the sponsor up to $10,000 and $65,000 of contingent consideration related to the Blair Contribution and the Whitehall Contribution, respectively.  The payments are based on achievement of certain levels of Adjusted EBITDA in 2017 and 2018.  Achievement of these threshold levels of Adjusted EBITDA, as defined in each of the contribution agreements, will be dependent on the quantity of volumes sold and related prices, which are forecasted at levels above current market prices.  The Partnership’s ability to meet such thresholds will be affected by events and circumstances beyond its control.  If market or other economic conditions remain the same or deteriorate, the thresholds may not be met. If the thresholds are not attained during each of the contingency periods, no payment will be owed to the sponsor.

A 10% increase or decrease in the achievement of Adjusted EBITDA versus current forecasts for the measurement periods could result in a range of potential payments under these arrangements which could differ from the current estimated fair value of the liabilities based on our current forecasts.  The following table outlines the original fair value reflected as the carrying value in the financial statements, the range of minimum and maximum undiscounted payments, and a sensitivity calculation of the current estimated fair value and sensitivities based on achieving Adjusted EBITDA levels 10% above or below the Partnership’s current forecasted results as of December 31, 2017.  Based on the significant estimates and assumptions included in the analysis, actual results could differ from these estimates.

			Undiscounted Payments				Sensitivity Analysis
Transaction	Carrying Value of Liability		Minimum (a)		Maximum		Current Estimated Fair Value		-10% Adjusted EBITDA		+10% Adjusted EBITDA
Blair Contribution	$	5,000	$	5,000	$	10,000	$	7,226	$	7,226	$	7,226
Whitehall Contribution	$	14,000	$	20,000	$	65,000	$	20,000	$	20,000	$	20,000

(a) The Partnership anticipates payment of $5,000 and $20,000 for the 2017 measurement periods related to the Blair Contribution and the Whitehall Contribution, respectively, in March 2018 to our sponsor pending approval from the conflicts committee.

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.

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Equity

12 Months Ended

Dec. 31, 2017

Equity [Abstract]

Equity

Equity

During the second quarter of 2017, our sponsor distributed its 20,693,643 common units in the Partnership to its members. As of December 31, 2017, our management team, together with our general partner's board of directors have a 10% direct ownership interest in our limited partnership units. In addition, our sponsor is the owner of our general partner.

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.

During the year ended December 31, 2017, the Partnership repurchased 2,030,163 common units for a total cost of $20,000 at an average price including commissions of $9.82 per unit.

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 did not issue 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. Our sponsor currently holds the incentive distribution rights, but may transfer these rights at any time.

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 are made after giving effect, if any, to priority income allocations in an amount equal to incentive cash distributions allocated 100% to our sponsor.

During the years ended December 31, 2017 and 2016, no income was allocated to our holders of incentive distribution rights. During the year ended December 31, 2015, $2,622 was allocated to our holders of 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 and our holders of incentive distribution rights will receive.

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 Holders of Incentive Distribution Rights
January 15, 2015	$	0.6750	January 30, 2015	February 13, 2015	$	24,947	$	1,311
April 16, 2015	$	0.6750	May 1, 2015	May 15, 2015	$	24,947	$	1,311
July 21, 2015	$	0.4750	August 5, 2015	August 14, 2015	$	17,555	$	—
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	$	—

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.

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,
	2017	2016	2015
Basic common units outstanding	86,518,249	49,567,268	36,958,988
Potentially dilutive common units	1,382,733	—	191,890
Diluted common units outstanding	87,900,982	49,567,268	37,150,878

For purposes of calculating the Partnership’s earnings per unit under the two-class method, common units are treated as participating preferred units, and the previously outstanding subordinated units were treated as the residual equity interest, or common equity. Incentive distribution rights are treated as participating securities.

Diluted earnings per unit excludes any dilutive awards granted (see Note 13 - Unit-Based Compensation) if their effect is anti-dilutive. Diluted earnings per unit for the years ended December 31, 2017 and 2015, includes the dilutive effect of 1,382,733 and 191,890, 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 holders is subject to the distribution waterfall in the partnership agreement. 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 Blair, Whitehall and Other Assets for all periods presented. The amounts of incremental income or losses recast to periods prior to the 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, 2017, 2016 and 2015 (in thousands, except per unit amounts):

	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	—		51,077		51,077
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	—		(84,519		)	(84,519		)
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	)

	Year Ended December 31, 2015
	General Partner and IDRs		Limited Partner Units			Total
Declared distribution	$	1,311	$	42,502		$	43,813
Assumed allocation of distributions in excess of earnings	—		(16,091		)	(16,091		)
Add back recast losses attributable to Blair	—		2,619			2,619
Add back recast income attributable to Whitehall and Other Assets	—		(2,076		)	(2,076		)
Assumed allocation of net income	$	1,311	$	26,954		$	28,265
Earnings per limited partner unit - basic			$	0.73
Earnings per limited partner unit - diluted			$	0.73

Recast Equity Transactions

On March 15, 2017, in connection with the closing of the Whitehall Contribution, $116,417 of sponsor advances were converted to capital, as reflected in the non-controlling interest section of the accompanying Consolidated Statement of Partners' Capital.

During the years ended December 31, 2016 and 2015, the sponsor paid $1,652 and $2,787, respectively, of expenses on behalf of Blair and Whitehall. Such transactions are recognized within the non-controlling interest section of the accompanying Consolidated Statement of Partners' Capital.

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Unit-Based Compensation

12 Months Ended

Dec. 31, 2017

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Unit-Based Compensation

Unit-Based Compensation

Long-Term Incentive Plan

On August 21, 2012, Hi-Crush GP 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 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, cancelled, 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’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, 2016	201,521		$	29.03
Granted	184,019		$	6.85
Forfeited	(39,399	)	$	52.53
Outstanding at December 31, 2017	346,141		$	14.56

As of December 31, 2017, total compensation expense not yet recognized related to unvested PPUs was $1,974, with a weighted average remaining service period of 1.6 years. The weighted average grant date fair value per unit for PPUs granted during the years ended December 31, 2017, 2016 and 2015 was $6.85, $15.94 and $37.52, respectively.

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.

	Units		Grant Date Weighted-Average Fair Value per Unit
Outstanding at December 31, 2016	378,260		$	16.40
Vested	(28,080	)	$	25.43
Granted	720,923		$	8.94
Forfeited	(34,511	)	$	16.22
Outstanding at December 31, 2017	1,036,592		$	10.97

As of December 31, 2017, total compensation expense not yet recognized related to unvested TPUs was $7,521, 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, 2017, 2016 and 2015 was $8.94, $12.96 and $34.09, respectively. The total fair value of units vested during the years ended December 31, 2017, 2016 and 2015 was $714, $62 and $42, respectively.

Director Unit Grants

The Partnership issued 29,148, 103,377 and 6,344 common units to certain of its directors during the years ended December 31, 2017, 2016 and 2015, respectively. In January 2018, the Partnership issued 36,109 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 employees 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. With respect to any eligible individuals electing to participate in the Second 2017 UPP who were also participating in the 2017 UPP, any contributions that were made to the 2017 UPP and not withdrawn by a participant before September 14, 2017 were applied to the Second 2017 UPP. 

Based on the current elected contributions, the participants will have the right to purchase an aggregate of approximately 347,000 common units. As of December 31, 2017, total accumulated contributions of $438 from directors under the Second 2017 UPP is maintained within the accrued and other current liabilities line item on our Consolidated Balance Sheet.

Compensation Expense

The following table presents total unit-based compensation expense:

	Year Ended December 31,
	2017		2016		2015
Performance Phantom Units	$	1,549	$	634	$	1,973
Time-Based Phantom Units	3,149		1,359		724
Director and other unit grants	499		474		273
Unit Purchase Programs	517		153		13
Total compensation expense	$	5,714	$	2,620	$	2,983

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Related Party Transactions

12 Months Ended

Dec. 31, 2017

Related Party Transactions [Abstract]

Related Party Transactions

Related Party Transactions

Effective August 16, 2012, our sponsor entered into a services agreement (the "Services Agreement") with our general partner, Hi-Crush Services LLC ("Hi-Crush Services") and the Partnership, pursuant to which Hi-Crush Services provides certain management and administrative services to the Partnership to assist in operating the Partnership’s business. Under the Services Agreement, the Partnership reimburses Hi-Crush Services and its affiliates, on a monthly basis, for the allocable expenses it incurs in its performance under the Services Agreement. These expenses include, among other things, administrative, rent and other expenses for individuals and entities that perform services for the Partnership. Hi-Crush Services and its affiliates will not be liable to the Partnership for its performance of services under the Services Agreement, except for liabilities resulting from gross negligence. During the years ended December 31, 2017, 2016 and 2015, the Partnership incurred $5,521, $4,938 and $5,260, respectively, of management and administrative service expenses from Hi-Crush Services.

In the normal course of business, our sponsor and its affiliates, including Hi-Crush Services, and the Partnership may from time to time make payments on behalf of each other.

As of December 31, 2017 and 2016, an outstanding balance of $12,399 and $118,641, respectively, payable to our sponsor is maintained as a current liability under the caption "Due to sponsor". On March 15, 2017 and August 31, 2016, $116,417 and $120,950, respectively, of sponsor advances were converted into capital. The December 31, 2016 balance was primarily related to construction advances made to Whitehall.

During the year ended December 31, 2015, the Partnership purchased $2,754 of sand from Goose Landing, LLC, a wholly owned subsidiary of Northern Frac Proppants II, LLC, which is reflected in cost of goods sold. During the years ended December 31, 2017 and 2016, the Partnership did not purchase any sand from Goose Landing, LLC. The father of Mr. Alston, who is a director of our general partner, owned a beneficial equity interest in Northern Frac Proppants II, LLC.

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. As of December 31, 2017 and 2016, the Partnership purchased $6,593 and $1,566, respectively, of equipment from PropX, which is reflected in property, plant and equipment. As of December 31, 2017 and 2016, the Partnership had accounts payable of $1,273 and $1,553, 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, 2017 and 2016, we incurred $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, 2017, 2016 and 2015, 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 is 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.

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Impairments and Other Expenses

12 Months Ended

Dec. 31, 2017

Restructuring and Related Activities [Abstract]

Impairments and Other Expenses

Impairments and Other Expenses

During the year ended December 31, 2016, the Partnership recognized a $33,745 impairment loss of all goodwill. Our goodwill arose from the acquisition of D&I in 2013 and is therefore allocated to the D&I reporting unit. We performed our annual assessment of the recoverability of goodwill during the third quarter of 2015. As part of the first step of goodwill impairment testing, we updated our assessment of our future cash flows, applying expected long-term growth rates, discount rates, and terminal values that we considered reasonable. We calculated a present value of the cash flows to arrive at an estimate of fair value under the income approach, and then used the market approach to corroborate this value. As a result of these estimates, we determined that there was no impairment of goodwill as of our annual assessment date. In addition, we reviewed and assessed various factors during the fourth quarter of 2015 and we determined that there was no impairment of goodwill as of December 31, 2015.

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.

During the year ended December 31, 2015, we completed an impairment assessment of the intangible asset associated with the Sand Supply Agreement.  Given market conditions, coupled with our ability to internally produce sand on more favorable terms, we determined that the fair value of the agreement was less than its carrying value, resulting in an impairment of $18,606. The Partnership did not recognize any impairments for intangible assets during the years ended December 31, 2017 and 2016.

During the year ended December 31, 2015, we elected to temporarily idle five destination transload facilities and three rail origin transload facilities.  In addition, to consolidate our administrative functions, we closed down a regional office facility. As a result of these actions, we recognized an impairment of $6,186 related to the write down of transload and office facilities’ assets to their net realizable value, and severance, retention and relocation costs of $571 for affected employees. No impairment charges were recorded for long-lived assets during the years ended December 31, 2017 and 2016.

We recognized impairments and other expenses as outlined in the following table:

	Year Ended December 31,
	2017		2016		2015
Impairment of Goodwill	$	—	$	33,745	$	—
Impairment of Sand Supply Agreement	—		—		18,606
Impairment of idled administrative and transload facilities	—		—		6,186
Severance, retention and relocation	40		280		571
Exploration expenses	143		—		—
Abandonment of construction projects	460		—		256
Expiration of exclusivity agreements	222		—		40
Impairments and other expenses	$	865	$	34,025	$	25,659

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Segment Reporting

12 Months Ended

Dec. 31, 2017

Segment Reporting [Abstract]

Segment Reporting

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.

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Concentration of Credit Risk

12 Months Ended

Dec. 31, 2017

Risks and Uncertainties [Abstract]

Concentration of Credit Risk

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, 2017, 2016 and 2015:

	Year Ended December 31,
	2017		2016		2015
Customer A	*		*		11	%
Customer B	26	%	28	%	26	%
Customer C	11	%	17	%	12	%
Customer D	*		14	%	*
Customer E	*		19	%	19	%

*  Less than ten percent

Throughout 2017, the Partnership has maintained cash balances in excess of federally insured amounts on deposit with financial institutions.

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Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2017

Quarterly Financial Information Disclosure [Abstract]

Quarterly Financial Data (Unaudited)

Quarterly Financial Data (Unaudited)

As discussed in Note 2 - Basis of Presentation, the Blair 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 Blair for the first and second quarters of 2016 and to include Whitehall and Other Assets for all 2016 periods presented.

2017	First Quarter (a)			Second Quarter			Third Quarter (b)			Fourth Quarter			Total
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	(3,338		)	18,524			32,479			50,384			98,049
Net income (loss)	(6,831		)	16,380			29,807			43,178			82,534
Earnings (loss) per limited partner unit:
Basic	$	(0.07	)	$	0.18		$	0.33		$	0.48		$	0.97
2016
Revenues	$	52,148		$	38,429		$	46,556		$	67,297		$	204,430
Gross profit (loss)	(7		)	(1,262		)	(57		)	416			(910		)
Loss from operations	(48,860		)	(8,088		)	(8,813		)	(5,105		)	(70,866		)
Net loss	(52,500		)	(12,159		)	(11,734		)	(8,126		)	(84,519		)
Loss per limited partner unit:
Basic	$	(1.39	)	$	(0.26	)	$	(0.21	)	$	(0.11	)	$	(1.64	)

(a) The first quarter of 2016 includes a $33,745 impairment of goodwill. Refer to Note 15 for additional disclosure.

(b) The third quarter of 2017 includes $3,554 of other operating income related to a contract dispute that was subsequently resolved.

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Subsequent Events

12 Months Ended

Dec. 31, 2017

Subsequent Events [Abstract]

Subsequent Events

Subsequent Events

On January 17, 2018, our general partner's board of directors declared a cash distribution for the fourth quarter of 2017 totaling $17,809, or $0.20 per common unit. This distribution was paid on February 13, 2018 to unitholders of record on February 1, 2018. No distributions were declared for our holders of incentive distribution rights.

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Schedule II - Valuation and Qualifying Accounts

12 Months Ended

Dec. 31, 2017

Valuation and Qualifying Accounts [Abstract]

Schedule II - Valuation and Qualifying Accounts

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, 2017	$	1,549	$	—	$	(489	)	$	1,060
Year Ended December 31, 2016	$	663	$	8,236	$	(7,350	)	$	1,549
Year Ended December 31, 2015	$	984	$	101	$	(422	)	$	663

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Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2017

Accounting Policies [Abstract]

Use of Estimates

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

Cash and cash equivalents consist of all cash balances and highly liquid investments with an original maturity of three months or less.

Accounts Receivable

Accounts Receivable

Trade receivables relate to sales of raw 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.

Deferred Charges

Deferred 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 $1,391, $1,866 and $2,293 for the years ended December 31, 2017, 2016 and 2015, respectively.

On December 22, 2017, the Partnership replaced our amended and restated credit agreement (the "Prior Revolving Credit Agreement") and our 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.

On April 28, 2016 and November 5, 2015, we amended our Prior Revolving Credit Agreement. As a result of these modifications, we accelerated amortization of $349 and $662, respectively, representing a portion of the remaining unamortized balance of debt issuance costs, which is included in interest expense.

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. In connection with the refinancing in December 2017, the Partnership incurred debt issuance costs of $4,731 that were capitalized. As of December 31, 2017 and 2016, the Partnership maintained unamortized debt issuance costs of $3,643 and $3,538 within long-term debt, respectively and $1,070 and $913 within other assets, respectively. Balances maintained in other assets represent costs associated with our revolving credit facility.

Inventories

Inventories

Sand inventory is stated at the lower of cost or net realizable value using the average cost method.

Inventory manufactured at our plant 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.

Property, Plant and Equipment

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 line in the 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.

Impairment of Long-lived Assets

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.

Goodwill and Intangible Assets

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 all goodwill. Refer to Note 15 - Impairments and Other 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.

Equity Method Investments

Equity Method Investments

The Partnership accounts for investments, which 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

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.  In connection with its recent acquisitions of Blair and Whitehall and Other Assets from its sponsor, the Partnership has entered into certain contingent consideration arrangements.  As such transactions are between entities under common control, any differences between the calculated fair value, and the actual resulting payments in the future will be reflected as an equity adjustment to the deemed distributions associated with the acquisitions.

Asset Retirement Obligations

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

Revenue Recognition

Frac sand sales revenues are recognized when legal title passes to the customer, which may occur at the production facility, rail origin, terminal or wellsite. At that point, delivery has occurred, evidence of a contractual arrangement exists and collectability is reasonably assured. Amounts received from customers in advance of sand deliveries are recorded as deferred revenue. As of December 31, 2017, the Partnership has recorded a total liability of $11,783 for prepayments of future deliveries of frac sand. These prepayments are refundable in the event that the Partnership is unable to meet the minimum sand volumes required under the contract.

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 2018 and 2024. The agreements define, among other commitments, the volume of product that the Partnership must provide, the price that will be charged to the customer, and the volume that the customer must purchase by the end of the defined cure periods, which can range from three months to the end of a contract year.

Revenue from make-whole provisions in our customer contracts is recognized at the end of the defined cure period when collectability is certain. Customer prepayments in excess of customer obligations remaining on account upon the termination of a contract are recognized as other operating income during the period in which the 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. During the year ended December 31, 2015, the Partnership recognized $12,310 as part of a settlement payment for past and future obligations under a customer contract, which is included in other operating income on our Consolidated Statements of Operations.

Transportation services revenues are recognized as the services have been completed, meaning the related services have been rendered. At that point, delivery of service has occurred, evidence of a contractual arrangement exists and collectability is reasonably assured.

Fair Value of Financial Instruments

Fair Value of Financial Instruments

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 fair value of the senior secured term loan approximated $198,015 as of December 31, 2017, based on the market price quoted from external sources, compared with a carrying value of $200,000. If the senior secured term loan was measured at fair value in the financial statements, it would be classified as Level 2 in the fair value hierarchy.

Net Income per Limited Partner Unit

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.

As described in Note 2 - Basis of Presentation, the Partnership's historical financial information has been recast to consolidate Blair, Whitehall and Other Assets for all periods presented. The amounts of incremental income or losses recast to periods prior to the Blair Contribution and Whitehall Contribution are excluded from the calculation of net income per limited partner unit.

Income Taxes

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.

Recent Accounting Pronouncements

Recent Accounting Pronouncements

In May 2017, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update No. 2017-09 ("ASU 2017-09"), Compensation - Stock Compensation (Topic 718): Scope of Modification Accounting. This update provides guidance about which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting in Topic 718. The amendments in this update will be applied prospectively to an award modified on or after the adoption date. ASU 2017-09 is effective for the Partnership beginning after December 15, 2017, with early adoption permitted. The Partnership is currently assessing the impact that adopting this new accounting guidance will have on its Consolidated Financial Statements and footnote disclosures.

In January 2017, the FASB issued Accounting Standards Update No. 2017-03 ("ASU 2017-03"), Accounting Changes and Error Corrections (Topic 250) and Investments-Equity Method and Joint Ventures (Topic 323): Amendments to SEC Paragraphs Pursuant to Staff Announcements at the September 22, 2016 and November 17, 2016 EITF Meetings. This update adds language to the SEC Staff Guidance in relation to ASU 2014-09, ASU 2016-02, and ASU 2016-13. This ASU 2017-03 provides the SEC Staff view that a registrant should consider additional quantitative and qualitative disclosures related to the previously mentioned ASUs in connection with the status and impact of their adoption. This guidance, which was effective immediately, did not have a material impact on our Consolidated Financial Statements.

In January 2017, the FASB issued Accounting Standards Update No. 2017-01 ("ASU 2017-01"), Business Combinations (Topic 805): Clarifying the Definition of a Business. This update clarifies the definition of a business and provides additional guidance for determining whether transactions should be accounted for as acquisitions of assets or business. The amendment was effective for the Partnership beginning January 1, 2018, with early adoption permitted, and should be applied prospectively. The Partnership is currently assessing the impact that adopting this new accounting guidance will have on its Consolidated Financial Statements and footnote disclosures, but does not anticipate that adoption will have a material impact on its financial position, results of operations or cash flows.

In February 2016, the FASB issued Accounting Standards Update No. 2016-02 ("ASU 2016-02"), Leases (Topic 842). This update will impact all leases with durations greater than twelve months. In general, such arrangements will be 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 will be recorded for all leases, whether operating or financing, while the statement of operations will reflect 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 will be calculated using the applicable incremental borrowing rate at the date of adoption. The new accounting guidance is effective for the Partnership beginning in the first quarter of 2019, and should be applied retrospectively. The FASB has also issued the following standard which clarifies ASU 2016-02 and has 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). The Partnership is currently assessing the impact that adopting this new accounting guidance will have on its Consolidated Financial Statements and footnote disclosures.

In May 2014, the FASB issued Accounting Standards Update No. 2014-09 ("ASU 2014-09"), Revenue from Contracts with Customers (Topic 606). This update supersedes the most current revenue recognition guidance, as well as some cost recognition guidance. The update requires that an entity recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This update also requires new qualitative and quantitative disclosures about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts, including significant judgments and changes in judgments, information about contract balances and performance obligations, and assets recognized from costs incurred to obtain or fulfill a contract. The authoritative guidance, which may be applied on a full retrospective or modified retrospective basis whereby the entity records a cumulative effect of initially applying this update at the date of initial application, was effective for the Partnership beginning January 1, 2018. The FASB has also issued the following standards which clarify ASU 2014-09 and have the same effective date as the original standard: ASU 2016-12, Revenue from Contracts with Customers: Narrow- Scope Improvements and Practical Expedients, ASU 2016-10 Revenue from Contracts with Customers: Identifying Performance Obligations and Licensing and ASU 2017-13, Revenue Recognition (Topic 605), Revenue from Contracts with Customers (Topic 606), Leases (Topic 840), and Leases (Topic 842).

The Partnership has completed its assessment of the impacts of the adoption of ASU 2014-09. We adopted ASU 2014-09 on January 1, 2018, using the full retrospective approach and it will be fully presented in the Partnership’s Quarterly Report on Form 10-Q for the three months ended March 31, 2018. We finalized the documentation on our assessment of our contracts and determined that there is no impact on our revenue recognition practices or impact to our Consolidated Financial Statements. The adoption of ASU 2014-09 will also result in additional disclosures regarding revenue recognition, disaggregation of revenue types and deferred revenue contract liabilities. The Partnership generates revenue by excavating, processing and delivering frac sand and providing related services and recognizes revenue at the point of delivery to customers or completion of services, at which point the earnings process is deemed to be complete. Amounts received from customers in advance of sand deliveries are recorded as deferred revenue.

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Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2017

Accounting Policies [Abstract]

Future Amortization Expense of Deferred Charges

The following is a summary of future amortization expense associated with deferred charges:

For the years ending December 31,
2018	$	673
2019	673
2020	673
2021	673
2022	673
Thereafter	1,348
Total	$	4,713

Estimated Useful Lives of Property, Plant and Equipment

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

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Acquisitions (Tables)

12 Months Ended

Dec. 31, 2017

Business Combinations [Abstract]

Schedule Of Total Purchase Consideration, Asset Acquisition

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

Schedule of Recognized Identified Assets Acquired and Liabilities Assumed

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 liabilities 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 payable in the future.

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 liabilities 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 payable in the future.

Business Acquisition, Recast Financial Information

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 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, 2017
	Partnership Historical		Whitehall and Other Assets through  March 15, 2017			Eliminations			Partnership Recast (Supplemental)
Revenues	$	602,623	$	—		$	—		$	602,623
Net income (loss)	$	83,979	$	(1,366	)	$	(79	)	$	82,534
Net income (loss) attributable to Hi-Crush Partners LP	$	84,005	$	(1,392	)	$	(79	)	$	82,534
Net income per limited partner unit - basic	$	0.97							$	0.95

	Year Ended December 31, 2016
	Partnership Historical			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	)	$	716	$	(3,778	)	$	(45	)	$	(84,519	)
Net income (loss) attributable to Hi-Crush Partners LP	$	(81,313	)	$	716	$	(3,877	)	$	(45	)	$	(84,519	)
Net loss per limited partner unit - basic	$	(1.64	)									$	(1.71	)

	Year Ended December 31, 2015
	Partnership Historical		Blair			Whitehall and Other Assets		Eliminations			Partnership Recast (Supplemental)
Revenues	$	339,640	$	—		$	33,217	$	(33,217	)	$	339,640
Net income (loss)	$	28,410	$	(2,619	)	$	1,645	$	286		$	27,722
Net income (loss) attributable to Hi-Crush Partners LP	$	28,265	$	(2,619	)	$	1,790	$	286		$	27,722
Net income per limited partner unit - basic	$	0.73									$	0.71

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Inventories (Tables)

12 Months Ended

Dec. 31, 2017

Inventory Disclosure [Abstract]

Components of Inventories

Inventories consisted of the following:

	December 31,
	2017		2016
Raw material	$	498	$	—
Work-in-process	18,739		17,836
Finished goods	22,892		9,416
Spare parts	2,143		2,025
Inventories	$	44,272	$	29,277

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Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2017

Property, Plant and Equipment [Abstract]

Components of Property, Plant and Equipment

Property, plant and equipment consisted of the following:

	December 31,
	2017			2016
Buildings	$	21,532		$	16,929
Mining property and mine development	381,653			113,169
Plant and equipment	389,197			331,165
Rail and rail equipment	55,783			56,369
Transload facilities and equipment	121,522			78,105
Construction-in-progress	14,454			1,695
Property, plant and equipment	984,141			597,432
Less: Accumulated depreciation and depletion	(84,983		)	(55,739		)
Property, plant and equipment, net	$	899,158		$	541,693

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Goodwill and Intangible Assets (Tables)

12 Months Ended

Dec. 31, 2017

Goodwill and Intangible Assets Disclosure [Abstract]

Changes in Goodwill and Intangible Assets

Changes in goodwill and intangible assets consisted of the following:

	Goodwill			Intangible Assets
Balance at December 31, 2015	$	33,745		$	11,779
Loss on impairment (Note 15)	(33,745		)	—
Amortization expense	—			(1,682		)
Balance at December 31, 2016	—			10,097
Amortization expense	—			(1,681		)
Balance at December 31, 2017	$	—		$	8,416

Intangible Assets, Arising from Acquisition

Intangible assets arising from the acquisition of D&I consisted of the following:

		December 31,
	Useful life	2017			2016
Supplier agreements	1-20 Years	$	21,997		$	21,997
Customer contracts and relationships	1-10 Years	18,132			18,132
Other intangible assets	1-3 Years	1,749			1,749
Intangible assets		41,878			41,878
Less: Accumulated amortization and impairments		(33,462		)	(31,781		)
Intangible assets, net		$	8,416		$	10,097

Future Amortization Expense of Intangible Assets

As of December 31, 2017, future amortization is as follows:

Fiscal Year	Amortization
2018	$	1,682
2019	1,682
2020	1,682
2021	1,682
2022	1,682
Thereafter	6
	$	8,416

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Accrued and Other Current Liabilities (Tables)

12 Months Ended

Dec. 31, 2017

Payables and Accruals [Abstract]

Components of Accrued and Other Current Liabilities

Accrued and other current liabilities consisted of the following:

	December 31,
	2017		2016
Accrued royalty payments	$	8,763	$	3,436
Accrued logistics costs	5,878		763
Accrued compensation and benefits	7,150		1,833
Accrued taxes payable	5,139		389
Accrued interest payable	505		339
Other current liabilities	2,496		1,395
Accrued and other current liabilities	$	29,931	$	8,155

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Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2017

Debt Disclosure [Abstract]

Components of Long-Term Debt

Long-term debt consisted of the following:

	December 31,
	2017			2016
Revolving Credit Agreement	$	—		$	—
Prior Revolving Credit Agreement	—			—
Term Loan Credit Facility	200,000			—
Prior Term Loan Credit Facility	—			194,500
Less: Unamortized original issue discount	(1,992		)	(1,247		)
Less: Unamortized debt issuance costs	(3,643		)	(3,538		)
Other notes payable	3,054			6,705
Total debt	197,419			196,420
Less: current portion of long-term debt	(2,957		)	(2,962		)
Long-term debt	$	194,462		$	193,458

Schedule of Maturities of Long-term Debt

As of December 31, 2017, future minimum debt repayments, excluding original issue discount and debt issuance costs, are as follows:

Fiscal Year	Amount
2018	$	2,957
2019	4,097
2020	2,000
2021	2,000
2022	2,000
Thereafter	190,000
	$	203,054

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Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2017

Asset Retirement Obligation [Abstract]

Reconciliation of Total Reclamation Liability for 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, 2014	$	8,317
Accretion expense	394
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

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2017

Commitments and Contingencies Disclosure [Abstract]

Schedule of Contractual Obligations

As of December 31, 2017, future minimum operating lease payments and minimum purchase commitments are as follows:

Fiscal Year	Operating Leases		Minimum Purchase Commitments
2018	$	33,787	$	5,571
2019	33,638		2,616
2020	30,831		2,296
2021	24,068		2,296
2022	18,036		2,296
Thereafter	16,670		1,871
	$	157,030	$	16,946

Schedule of Business Acquisitions, Contingent Consideration

The following table outlines the original fair value reflected as the carrying value in the financial statements, the range of minimum and maximum undiscounted payments, and a sensitivity calculation of the current estimated fair value and sensitivities based on achieving Adjusted EBITDA levels 10% above or below the Partnership’s current forecasted results as of December 31, 2017.  Based on the significant estimates and assumptions included in the analysis, actual results could differ from these estimates.

			Undiscounted Payments				Sensitivity Analysis
Transaction	Carrying Value of Liability		Minimum (a)		Maximum		Current Estimated Fair Value		-10% Adjusted EBITDA		+10% Adjusted EBITDA
Blair Contribution	$	5,000	$	5,000	$	10,000	$	7,226	$	7,226	$	7,226
Whitehall Contribution	$	14,000	$	20,000	$	65,000	$	20,000	$	20,000	$	20,000

(a) The Partnership anticipates payment of $5,000 and $20,000 for the 2017 measurement periods related to the Blair Contribution and the Whitehall Contribution, respectively, in March 2018 to our sponsor pending approval from the conflicts committee.

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Equity (Tables)

12 Months Ended

Dec. 31, 2017

Equity [Abstract]

Schedule of Distributions Made to Limited Partner Unitholders

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 Holders of Incentive Distribution Rights
January 15, 2015	$	0.6750	January 30, 2015	February 13, 2015	$	24,947	$	1,311
April 16, 2015	$	0.6750	May 1, 2015	May 15, 2015	$	24,947	$	1,311
July 21, 2015	$	0.4750	August 5, 2015	August 14, 2015	$	17,555	$	—
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	$	—

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.

Schedule of Weighted Average Limited Partner Units Outstanding

The following table outlines our basic and diluted, weighted average limited partner units outstanding during the relevant periods:

	Year Ended December 31,
	2017	2016	2015
Basic common units outstanding	86,518,249	49,567,268	36,958,988
Potentially dilutive common units	1,382,733	—	191,890
Diluted common units outstanding	87,900,982	49,567,268	37,150,878

Schedule of Net Income Attributable to Limited Partners

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, 2017, 2016 and 2015 (in thousands, except per unit amounts):

	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	—		51,077		51,077
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	—		(84,519		)	(84,519		)
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	)

	Year Ended December 31, 2015
	General Partner and IDRs		Limited Partner Units			Total
Declared distribution	$	1,311	$	42,502		$	43,813
Assumed allocation of distributions in excess of earnings	—		(16,091		)	(16,091		)
Add back recast losses attributable to Blair	—		2,619			2,619
Add back recast income attributable to Whitehall and Other Assets	—		(2,076		)	(2,076		)
Assumed allocation of net income	$	1,311	$	26,954		$	28,265
Earnings per limited partner unit - basic			$	0.73
Earnings per limited partner unit - diluted			$	0.73

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Unit-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2017

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Schedule of Performance Phantom Units Activity

The following table presents information relative to our PPUs.

	Units		Grant Date Weighted-Average Fair Value per Unit
Outstanding at December 31, 2016	201,521		$	29.03
Granted	184,019		$	6.85
Forfeited	(39,399	)	$	52.53
Outstanding at December 31, 2017	346,141		$	14.56

Schedule of Time-Based Phantom Units Activity

The following table presents information relative to our TPUs.

	Units		Grant Date Weighted-Average Fair Value per Unit
Outstanding at December 31, 2016	378,260		$	16.40
Vested	(28,080	)	$	25.43
Granted	720,923		$	8.94
Forfeited	(34,511	)	$	16.22
Outstanding at December 31, 2017	1,036,592		$	10.97

Schedule of Unit-based Compensation Expense

The following table presents total unit-based compensation expense:

	Year Ended December 31,
	2017		2016		2015
Performance Phantom Units	$	1,549	$	634	$	1,973
Time-Based Phantom Units	3,149		1,359		724
Director and other unit grants	499		474		273
Unit Purchase Programs	517		153		13
Total compensation expense	$	5,714	$	2,620	$	2,983

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Impairments and Other Expenses (Tables)

12 Months Ended

Dec. 31, 2017

Restructuring and Related Activities [Abstract]

Impairments and Other Expenses

We recognized impairments and other expenses as outlined in the following table:

	Year Ended December 31,
	2017		2016		2015
Impairment of Goodwill	$	—	$	33,745	$	—
Impairment of Sand Supply Agreement	—		—		18,606
Impairment of idled administrative and transload facilities	—		—		6,186
Severance, retention and relocation	40		280		571
Exploration expenses	143		—		—
Abandonment of construction projects	460		—		256
Expiration of exclusivity agreements	222		—		40
Impairments and other expenses	$	865	$	34,025	$	25,659

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Concentration of Credit Risk (Tables)

12 Months Ended

Dec. 31, 2017

Risks and Uncertainties [Abstract]

Schedule of Concentration of Credit Risk

The following table provides our significant customers that had sales greater than 10% for the years ended December 31, 2017, 2016 and 2015:

	Year Ended December 31,
	2017		2016		2015
Customer A	*		*		11	%
Customer B	26	%	28	%	26	%
Customer C	11	%	17	%	12	%
Customer D	*		14	%	*
Customer E	*		19	%	19	%

*  Less than ten percent

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Quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2017

Quarterly Financial Information Disclosure [Abstract]

Summary of Quarterly Financial Data

As discussed in Note 2 - Basis of Presentation, the Blair 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 Blair for the first and second quarters of 2016 and to include Whitehall and Other Assets for all 2016 periods presented.

2017	First Quarter (a)			Second Quarter			Third Quarter (b)			Fourth Quarter			Total
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	(3,338		)	18,524			32,479			50,384			98,049
Net income (loss)	(6,831		)	16,380			29,807			43,178			82,534
Earnings (loss) per limited partner unit:
Basic	$	(0.07	)	$	0.18		$	0.33		$	0.48		$	0.97
2016
Revenues	$	52,148		$	38,429		$	46,556		$	67,297		$	204,430
Gross profit (loss)	(7		)	(1,262		)	(57		)	416			(910		)
Loss from operations	(48,860		)	(8,088		)	(8,813		)	(5,105		)	(70,866		)
Net loss	(52,500		)	(12,159		)	(11,734		)	(8,126		)	(84,519		)
Loss per limited partner unit:
Basic	$	(1.39	)	$	(0.26	)	$	(0.21	)	$	(0.11	)	$	(1.64	)

(a) The first quarter of 2016 includes a $33,745 impairment of goodwill. Refer to Note 15 for additional disclosure.

(b) The third quarter of 2017 includes $3,554 of other operating income related to a contract dispute that was subsequently resolved.

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Business and Organization - Narrative (Details) $ in Thousands				12 Months Ended
	Mar. 15, 2017 USD ($)	Mar. 03, 2017 USD ($) a shares	Aug. 31, 2016 USD ($) shares	Dec. 31, 2017 USD ($) shares	Dec. 31, 2016 USD ($)	[1]	Dec. 31, 2015 USD ($)	[1],[2]	Apr. 08, 2014	May 08, 2012
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Percentage of limited partner interest										100.00%
Business Acquisition [Line Items]
Payments to acquire business				$ 140,000	$ 75,000		$ 0
Cash paid to sellers		$ 200,000
Issuance of common units for an asset acquisition (in units) | shares				3,438,789
Issuance of common units for asset acquisition		$ 62,242		$ 62,242
Common Units
Business Acquisition [Line Items]
Issuance of common units for an asset acquisition (in units) | shares		3,438,789
Hi-Crush Augusta LLC
Business Acquisition [Line Items]
Ownership percentage	2.00%								98.00%
Hi-Crush Blair LLC
Business Acquisition [Line Items]
Payments to acquire business			$ 75,000
Business acquisition, maximum contingent consideration to pay			$ 10,000
Hi-Crush Blair LLC | Common Units
Business Acquisition [Line Items]
Business acquisition, number of shares issued (in units) | shares			7,053,292
Hi-Crush Whitehall LLC and Other Assets
Business Acquisition [Line Items]
Payments to acquire business	$ 140,000
Business acquisition, maximum contingent consideration to pay	$ 65,000
Business acquisition, contingent consideration period	2 years
Permian Basin Sand Company, LLC
Business Acquisition [Line Items]
Acres of frac sand reserves acquired | a		1,226

[1] Financial information has been recast to include the financial position and results attributable to Hi-Crush Whitehall LLC and Other Assets.

[2] Financial information has been recast to include the financial position and results attributable to Hi-Crush Blair LLC.

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Significant Accounting Policies - Narrative (Details) $ in Thousands	3 Months Ended		12 Months Ended
	Sep. 30, 2017 USD ($)	Mar. 31, 2016 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)		Dec. 31, 2015 USD ($) facility
Accounting Policies [Abstract]
Allowance for doubtful accounts			$ 1,060	$ 1,549
Allowance for doubtful accounts, write-off		$ 8,236
Line of Credit Facility [Line Items]
Amortization of debt financing costs			1,391	1,866		$ 2,293
Loss on extinguishment of debt			(4,332)	0	[1]	0	[1],[2]
Accelerated amortization of financing costs				349		662
Capitalized loan origination costs			4,731	128	[1]	406	[1],[2]
Carrying value of long-term debt			203,054
Property, Plant and Equipment [Line Items]
Impairment of idled administrative and transload facilities			0	0		6,186
Impairment of goodwill		$ 33,745	0	33,745		0
Impairment of intangible assets			0	0		18,606
Equity method investments			17,475	10,232	[1]
Capital contributions to PropX			7,168	10,232	[1]	0	[1],[2]
Earnings from equity method investments			75	0	[1]	0	[1],[2]
Deferred revenues			11,783
Other operating income	$ 3,554		$ 3,554	0	[1]	$ 12,310	[1],[2]
Minimum
Property, Plant and Equipment [Line Items]
Estimated useful life of intangible assets			1 year
Long-term Supply Agreements, expiration year			2018
Maximum
Property, Plant and Equipment [Line Items]
Estimated useful life of intangible assets			20 years
Long-term Supply Agreements, expiration year			2024
Transload facilities and equipment
Property, Plant and Equipment [Line Items]
Number of idled facilities | facility						5
Rail spurs and asset retirement obligations
Property, Plant and Equipment [Line Items]
Number of idled facilities | facility						3
Proppant Express Investments, LLC
Property, Plant and Equipment [Line Items]
Equity method investments			$ 17,475
Capital contributions to PropX			7,168	10,232
Earnings from equity method investments			75	0
Term Loan Credit Facility | $200M Term Loan Credit Facility
Line of Credit Facility [Line Items]
Unamortized debt issuance costs in long-term debt			3,643
Fair value of the senior secured term loan			198,015
Carrying value of long-term debt			200,000	0
Revolving Credit Facility
Line of Credit Facility [Line Items]
Unamortized debt issuance costs in other assets			1,070	$ 913
Carrying value of long-term debt			$ 0

[1] Financial information has been recast to include the financial position and results attributable to Hi-Crush Whitehall LLC and Other Assets.

[2] Financial information has been recast to include the financial position and results attributable to Hi-Crush Blair LLC.

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Significant Accounting Policies - Future Amortization Expense of Deferred Charges (Details) $ in Thousands	Dec. 31, 2017 USD ($)
Accounting Policies [Abstract]
Debt issuance costs, amortization expense, next twelve months	$ 673
Debt issuance costs, amortization expense, year two	673
Debt issuance costs, amortization expense, year three	673
Debt issuance costs, amortization expense, year four	673
Debt issuance costs, amortization expense, year five	673
Debt issuance costs, amortization expense, after year five	1,348
Total unamortized debt issuance costs	$ 4,713

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Significant Accounting Policies - Estimated Useful Lives of Property, Plant and Equipment (Details)	12 Months Ended
	Dec. 31, 2017
Computer equipment
Property, Plant and Equipment [Line Items]
Estimated useful life of property, plant and equipment	3 years
Furniture and fixtures
Property, Plant and Equipment [Line Items]
Estimated useful life of property, plant and equipment	7 years
Vehicles
Property, Plant and Equipment [Line Items]
Estimated useful life of property, plant and equipment	5 years
Equipment | Minimum
Property, Plant and Equipment [Line Items]
Estimated useful life of property, plant and equipment	5 years
Equipment | Maximum
Property, Plant and Equipment [Line Items]
Estimated useful life of property, plant and equipment	15 years
Rail spurs and asset retirement obligations | Minimum
Property, Plant and Equipment [Line Items]
Estimated useful life of property, plant and equipment	17 years
Rail spurs and asset retirement obligations | Maximum
Property, Plant and Equipment [Line Items]
Estimated useful life of property, plant and equipment	33 years
Rail and rail equipment | Minimum
Property, Plant and Equipment [Line Items]
Estimated useful life of property, plant and equipment	15 years
Rail and rail equipment | Maximum
Property, Plant and Equipment [Line Items]
Estimated useful life of property, plant and equipment	20 years
Transload facilities and equipment | Minimum
Property, Plant and Equipment [Line Items]
Estimated useful life of property, plant and equipment	15 years
Transload facilities and equipment | Maximum
Property, Plant and Equipment [Line Items]
Estimated useful life of property, plant and equipment	25 years

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Acquisitions - Narrative (Details) $ in Thousands				1 Months Ended	12 Months Ended
	Mar. 15, 2017 USD ($)	Mar. 03, 2017 USD ($) a shares	Aug. 31, 2016 USD ($) shares	Mar. 31, 2018 USD ($)	Dec. 31, 2017 USD ($) shares	Dec. 31, 2016 USD ($)		Dec. 31, 2015 USD ($)	[1],[2]
Business Acquisition [Line Items]
Cash paid to sellers		$ 200,000
Issuance of common units for an asset acquisition (in units) | shares					3,438,789
Issuance of common units for asset acquisition		62,242			$ 62,242
Cost of Permian Basin Sand acquisition		$ 263,072
Payments to acquire business					140,000	$ 75,000	[1]	$ 0
Common Units
Business Acquisition [Line Items]
Issuance of common units for an asset acquisition (in units) | shares		3,438,789
Hi-Crush Whitehall LLC and Other Assets
Business Acquisition [Line Items]
Payments to acquire business	$ 140,000
Business acquisition, maximum contingent consideration to pay	$ 65,000
Business acquisition, contingent consideration period	2 years
Acquisition related costs					$ 588
Business acquisition, contingent consideration, value per each threshold	$ 20,000
Business acquisition, contingent consideration, value per cumulative period threshold	25,000
Estimated fair value of contingent consideration liability	$ 14,000
Hi-Crush Blair LLC
Business Acquisition [Line Items]
Payments to acquire business			$ 75,000
Business acquisition, maximum contingent consideration to pay			10,000
Acquisition related costs						$ 850
Business acquisition, contingent consideration, value per each threshold			5,000
Estimated fair value of contingent consideration liability			$ 5,000
Hi-Crush Blair LLC | Common Units
Business Acquisition [Line Items]
Business acquisition, number of shares issued (in units) | shares			7,053,292
Permian Basin Sand Company, LLC
Business Acquisition [Line Items]
Acres of frac sand reserves acquired | a		1,226
Forecast | Hi-Crush Whitehall LLC and Other Assets
Business Acquisition [Line Items]
Business acquisition, estimated future payment of contingent consideration				$ 20,000
Forecast | Hi-Crush Blair LLC
Business Acquisition [Line Items]
Business acquisition, estimated future payment of contingent consideration				$ 5,000

[1] Financial information has been recast to include the financial position and results attributable to Hi-Crush Whitehall LLC and Other Assets.

[2] Financial information has been recast to include the financial position and results attributable to Hi-Crush Blair LLC.

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Acquisitions - Summary of total purchase consideration for Permian Basin Sand Acquisition (Details) - USD ($) $ in Thousands		12 Months Ended
	Mar. 03, 2017	Dec. 31, 2017
Business Combinations [Abstract]
Cash paid to sellers	$ 200,000
Issuance of common units for asset acquisition	62,242	$ 62,242
Transaction costs associated with the acquisition	830
Cost of Permian Basin Sand acquisition	$ 263,072

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Acquisitions - Carrying value of Whitehall and Other Asset's assets and allocation of purchase price (Details) - Hi-Crush Whitehall LLC and Other Assets $ in Thousands	Mar. 15, 2017 USD ($)
Business Acquisition [Line Items]
Cash	$ 198
Inventories	4,941
Prepaid expenses and other current assets	3
Property, plant and equipment	124,811
Accounts payable	(938)
Accrued liabilities and other current liabilities	(386)
Due to Hi-Crush Partners LP	(2,615)
Asset retirement obligation	(1,716)
Total carrying value of net assets	124,298
Carrying value of sponsor's non-controlling interest prior to Whitehall Contribution	119,108
Excess purchase price over the acquired interest (a)	34,892	[1]
Cost of acquisition	$ 154,000

[1] 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 payable in the future.

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Acquisitions - Carrying value of Blair's assets and allocation of cash consideration paid (Details) - Hi-Crush Blair LLC $ in Thousands	Aug. 31, 2016 USD ($)
Business Acquisition [Line Items]
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 liabilities 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 net assets	123,563
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)	[1]
Cost of acquisition	$ 80,000

[1] 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 payable in the future.

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Acquisitions - Recast Financial Results (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended										12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	[1]	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	[2]	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Business Acquisition [Line Items]
Revenues	$ 216,456	$ 167,583		$ 135,220	$ 83,364	$ 67,297	$ 46,556	$ 38,429	$ 52,148		$ 602,623	$ 204,430	[3]	$ 339,640	[3],[4]
Net income (loss)											82,534	(84,519)		27,722
Net income (loss) attributable to Hi-Crush Partners LP	$ 43,178	$ 29,807		$ 16,380	$ (6,831)	$ (8,126)	$ (11,734)	$ (12,159)	$ (52,500)		$ 82,534	$ (84,519)	[3]	$ 27,722	[3],[4]
Net income (loss) per limited partner unit - basic (usd per unit)	$ 0.48	$ 0.33		$ 0.18	$ (0.07)	$ (0.11)	$ (0.21)	$ (0.26)	$ (1.39)		$ 0.97	$ (1.64)	[3]	$ 0.73	[3],[4]
Net income (loss) per limited partner unit - basic, pro forma (usd per unit)											$ 0.95	$ (1.71)		$ 0.71
Historical
Business Acquisition [Line Items]
Revenues											$ 602,623	$ 204,430		$ 339,640
Net income (loss)											83,979	(81,412)		28,410
Net income (loss) attributable to Hi-Crush Partners LP											84,005	(81,313)		28,265
Adjustment | Hi-Crush Blair LLC
Business Acquisition [Line Items]
Revenues												13,761		0
Net income (loss)												716		(2,619)
Net income (loss) attributable to Hi-Crush Partners LP												716		(2,619)
Adjustment | Hi-Crush Whitehall LLC and Other Assets
Business Acquisition [Line Items]
Revenues											0	8,275		33,217
Net income (loss)											(1,366)	(3,778)		1,645
Net income (loss) attributable to Hi-Crush Partners LP											(1,392)	(3,877)		1,790
Adjustment | Eliminations
Business Acquisition [Line Items]
Revenues											0	(22,036)		(33,217)
Net income (loss)											(79)	(45)		286
Net income (loss) attributable to Hi-Crush Partners LP											$ (79)	$ (45)		$ 286

[1] The third quarter of 2017 includes $3,554 of other operating income related to a contract dispute that was subsequently resolved.

[2] The first quarter of 2016 includes a $33,745 impairment of goodwill. Refer to Note 15 for additional disclosure.

[3] Financial information has been recast to include the financial position and results attributable to Hi-Crush Whitehall LLC and Other Assets.

[4] Financial information has been recast to include the financial position and results attributable to Hi-Crush Blair LLC.

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Inventories - Components of Inventories (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Inventory Disclosure [Abstract]
Raw material	$ 498	$ 0
Work-in-process	18,739	17,836
Finished goods	22,892	9,416
Spare parts	2,143	2,025
Inventories	$ 44,272	$ 29,277	[1]

[1] Financial information has been recast to include the financial position and results attributable to Hi-Crush Whitehall LLC and Other Assets.

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Property, Plant and Equipment - Components of Property, Plant and Equipment (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 984,141	$ 597,432
Less: Accumulated depreciation and depletion	(84,983)	(55,739)
Property, plant and equipment, net	899,158	541,693	[1]
Buildings
Property, Plant and Equipment [Line Items]
Property, plant and equipment	21,532	16,929
Mining property and mine development
Property, Plant and Equipment [Line Items]
Property, plant and equipment	381,653	113,169
Plant and equipment
Property, Plant and Equipment [Line Items]
Property, plant and equipment	389,197	331,165
Rail and rail equipment
Property, Plant and Equipment [Line Items]
Property, plant and equipment	55,783	56,369
Transload facilities and equipment
Property, Plant and Equipment [Line Items]
Property, plant and equipment	121,522	78,105
Construction-in-progress
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 14,454	$ 1,695

[1] Financial information has been recast to include the financial position and results attributable to Hi-Crush Whitehall LLC and Other Assets.

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Property, Plant and Equipment - Narrative (Details) - USD ($) $ in Thousands	1 Months Ended		12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Property, Plant and Equipment [Line Items]
Depreciation and depletion			$ 29,456	$ 17,039	[1]	$ 15,684	[1],[2]
(Gain) loss on disposal of fixed assets			92	(357)		72
Payments to acquire mineral rights			122,032	44,011	[1]	127,217	[1],[2]
Synthetic mineral rights acquired			984,141	597,432
Impairment of idled administrative and transload facilities			0	0		6,186
Abandonment of construction projects			460	0		$ 256
Mining Properties and Mineral Rights
Property, Plant and Equipment [Line Items]
Total amount to terminate royalty agreements				6,750
Payments to acquire mineral rights	$ 3,375	$ 3,375
Synthetic mineral rights acquired			6,750
Transload facilities and equipment
Property, Plant and Equipment [Line Items]
Synthetic mineral rights acquired			$ 121,522	$ 78,105

[1] Financial information has been recast to include the financial position and results attributable to Hi-Crush Whitehall LLC and Other Assets.

[2] Financial information has been recast to include the financial position and results attributable to Hi-Crush Blair LLC.

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Goodwill and Intangible Assets - Narrative (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Goodwill and Intangible Assets Disclosure [Abstract]
Impairment of goodwill	$ 33,745	$ 0	$ 33,745		$ 0
Amortization of intangible assets		$ 1,681	1,682	[1]	2,620	[1],[2]
Weighted average remaining life of intangible assets		5 years
Impairment of intangible assets		$ 0	$ 0		$ 18,606

[1] Financial information has been recast to include the financial position and results attributable to Hi-Crush Whitehall LLC and Other Assets.

[2] Financial information has been recast to include the financial position and results attributable to Hi-Crush Blair LLC.

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Goodwill and Intangible Assets - Changes in Goodwill and Intangible Assets (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Goodwill
Goodwill, beginning balance	$ 33,745	$ 0	$ 33,745
Loss on impairment of goodwill	(33,745)	0	(33,745)		$ 0
Goodwill, ending balance		0	0		33,745
Intangible Assets
Intangible assets, beginning balance	$ 11,779	10,097	11,779
Loss on impairment of intangible assets		0	0		(18,606)
Amortization of intangible assets		(1,681)	(1,682)	[1]	(2,620)	[1],[2]
Intangible assets, ending balance		$ 8,416	$ 10,097		$ 11,779

[1] Financial information has been recast to include the financial position and results attributable to Hi-Crush Whitehall LLC and Other Assets.

[2] Financial information has been recast to include the financial position and results attributable to Hi-Crush Blair LLC.

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Goodwill and Intangible Assets - Intangible Assets Arising from Acquisition (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Finite-Lived Intangible Assets And Liabilities [Line Items]
Intangible assets	$ 41,878	$ 41,878
Less: Accumulated amortization and impairments	(33,462)	(31,781)
Intangible assets, net	$ 8,416	10,097	$ 11,779
Minimum
Finite-Lived Intangible Assets And Liabilities [Line Items]
Estimated useful life of intangible assets	1 year
Maximum
Finite-Lived Intangible Assets And Liabilities [Line Items]
Estimated useful life of intangible assets	20 years
Supplier agreements
Finite-Lived Intangible Assets And Liabilities [Line Items]
Intangible assets	$ 21,997	21,997
Supplier agreements | Minimum
Finite-Lived Intangible Assets And Liabilities [Line Items]
Estimated useful life of intangible assets	1 year
Supplier agreements | Maximum
Finite-Lived Intangible Assets And Liabilities [Line Items]
Estimated useful life of intangible assets	20 years
Customer contracts and relationships
Finite-Lived Intangible Assets And Liabilities [Line Items]
Intangible assets	$ 18,132	18,132
Customer contracts and relationships | Minimum
Finite-Lived Intangible Assets And Liabilities [Line Items]
Estimated useful life of intangible assets	1 year
Customer contracts and relationships | Maximum
Finite-Lived Intangible Assets And Liabilities [Line Items]
Estimated useful life of intangible assets	10 years
Other intangible assets
Finite-Lived Intangible Assets And Liabilities [Line Items]
Intangible assets	$ 1,749	$ 1,749
Other intangible assets | Minimum
Finite-Lived Intangible Assets And Liabilities [Line Items]
Estimated useful life of intangible assets	1 year
Other intangible assets | Maximum
Finite-Lived Intangible Assets And Liabilities [Line Items]
Estimated useful life of intangible assets	3 years

XML

Goodwill and Intangible Assets - Future Amortization Expense of Intangible Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Goodwill and Intangible Assets Disclosure [Abstract]
Intangible assets, future amortization expense, next twelve months	$ 1,682
Intangible assets, future amortization expense, year two	1,682
Intangible assets, future amortization expense, year three	1,682
Intangible assets, future amortization expense, year four	1,682
Intangible assets, future amortization expense, year five	1,682
Intangible assets, future amortization expense, after year five	6
Intangible assets, net	$ 8,416	$ 10,097	$ 11,779

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Accrued and Other Current Liabilities - Components of Accrued and Other Current Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Payables and Accruals [Abstract]
Accrued royalty payments	$ 8,763	$ 3,436
Accrued logistics costs	5,878	763
Accrued compensation and benefits	7,150	1,833
Accrued taxes payable	5,139	389
Accrued interest payable	505	339
Other current liabilities	2,496	1,395
Accrued and other current liabilities	$ 29,931	$ 8,155	[1]

[1] Financial information has been recast to include the financial position and results attributable to Hi-Crush Whitehall LLC and Other Assets.

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Long-Term Debt - Components of Long-Term Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Line of Credit Facility [Line Items]
Partnership debt	$ 203,054
Total debt	197,419	$ 196,420
Less: current portion of long-term debt	(2,957)	(2,962)	[1]
Long-term debt	194,462	193,458	[1]
Other notes payable
Line of Credit Facility [Line Items]
Partnership debt	3,054	6,705
Revolving Credit Facility
Line of Credit Facility [Line Items]
Partnership debt	0
Revolving Credit Facility | $125M Revolving Credit Agreement
Line of Credit Facility [Line Items]
Partnership debt	0	0
Revolving Credit Facility | $75M Prior Revolving Credit Agreement
Line of Credit Facility [Line Items]
Partnership debt	0	0
Term Loan Credit Facility | $200M Term Loan Credit Facility
Line of Credit Facility [Line Items]
Partnership debt	200,000	0
Less: Unamortized original issue discount	(1,992)
Less: Unamortized debt issuance costs	(3,643)
Total debt	194,365
Term Loan Credit Facility | $200M Prior Term Loan Credit Facility
Line of Credit Facility [Line Items]
Partnership debt	$ 0	194,500
Less: Unamortized original issue discount		(1,247)
Less: Unamortized debt issuance costs		$ (3,538)

[1] Financial information has been recast to include the financial position and results attributable to Hi-Crush Whitehall LLC and Other Assets.

XML

Long-Term Debt - Narrative (Details)		1 Months Ended	12 Months Ended
	Dec. 22, 2017 USD ($)	Jan. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Oct. 12, 2017 USD ($)	Apr. 28, 2014 USD ($)
Line of Credit Facility [Line Items]
Letter of credit commitments			$ 20,666,000
Carrying value of long-term debt			203,054,000
Partnership debt			197,419,000	$ 196,420,000
Cash consideration paid to acquire land				2,500,000	$ 2,500,000	$ 2,500,000
Other notes payable
Line of Credit Facility [Line Items]
Carrying value of long-term debt			3,054,000	6,705,000
Prepayments made by Partnership on promissory notes			$ 3,651,000	3,896,000
Effective interest rate			0.74%
Other notes payable | Subsequent Event
Line of Credit Facility [Line Items]
Prepayments made by Partnership on promissory notes		$ 957,000
Promissory Note Due In October 2017 | Other notes payable
Line of Credit Facility [Line Items]
Partnership debt						$ 3,676,000
Terms of promissory note issued						3 years
Promissory Note Due In December 2018 | Other notes payable
Line of Credit Facility [Line Items]
Partnership debt					$ 3,676,000
Terms of promissory note issued					3 years
Promissory Note Due in December 2019 | Other notes payable
Line of Credit Facility [Line Items]
Partnership debt				$ 3,676,000
Terms of promissory note issued				3 years
Revolving Credit Facility
Line of Credit Facility [Line Items]
Carrying value of long-term debt			$ 0
Revolving Credit Facility | $75M Prior Revolving Credit Agreement
Line of Credit Facility [Line Items]
Covenant compliance, units repurchased, authorized amount							$ 20,000,000
Line of credit facility, maximum borrowing capacity			75,000,000
Carrying value of long-term debt			0	$ 0
Revolving Credit Facility | $125M Revolving Credit Agreement
Line of Credit Facility [Line Items]
Line of credit facility, maximum borrowing capacity			125,000,000
Undrawn borrowing capacity			104,334,000
Carrying value of long-term debt			$ 0	0
Maximum leverage ratio			3.25
Minimum interest coverage ratio			2.5
Asset coverage ratio			1.5
Revolving Credit Facility | $125M Revolving Credit Agreement | Base Rate | Minimum
Line of Credit Facility [Line Items]
Interest rate basis points of credit facility			1.50%
Revolving Credit Facility | $125M Revolving Credit Agreement | Base Rate | Maximum
Line of Credit Facility [Line Items]
Interest rate basis points of credit facility			2.25%
Revolving Credit Facility | $125M Revolving Credit Agreement | Eurodollar | Minimum
Line of Credit Facility [Line Items]
Interest rate basis points of credit facility			2.50%
Revolving Credit Facility | $125M Revolving Credit Agreement | Eurodollar | Maximum
Line of Credit Facility [Line Items]
Interest rate basis points of credit facility			3.25%
Letter of Credit | $75M Prior Revolving Credit Agreement
Line of Credit Facility [Line Items]
Line of credit facility, maximum borrowing capacity			$ 25,000,000
Letter of Credit | $125M Revolving Credit Agreement
Line of Credit Facility [Line Items]
Line of credit facility, maximum borrowing capacity			30,000,000
Swing line loan | $75M Prior Revolving Credit Agreement
Line of Credit Facility [Line Items]
Line of credit facility, maximum borrowing capacity			10,000,000
Swing line loan | $125M Revolving Credit Agreement
Line of Credit Facility [Line Items]
Line of credit facility, maximum borrowing capacity			10,000,000
Term Loan Credit Facility | $200M Prior Term Loan Credit Facility
Line of Credit Facility [Line Items]
Line of credit facility, maximum borrowing capacity								$ 200,000,000
Carrying value of long-term debt			0	194,500,000
Debt instrument, discount				1,247,000
Unamortized debt issuance costs in long-term debt				3,538,000
Term Loan Credit Facility | $200M Term Loan Credit Facility
Line of Credit Facility [Line Items]
Line of credit facility, maximum borrowing capacity	$ 200,000,000
Carrying value of long-term debt			200,000,000	$ 0
Line of credit facility, increase in commitment amount	$ 100,000,000
Partnership debt			194,365,000
Debt instrument, discount			1,992,000
Unamortized debt issuance costs in long-term debt			$ 3,643,000
Interest rate under Term Loan Credit Facility			5.41%
Term Loan Credit Facility | $200M Term Loan Credit Facility | Base Rate
Line of Credit Facility [Line Items]
Interest rate basis points of credit facility	2.75%
Increase in basis points of credit facility	0.25%
Term Loan Credit Facility | $200M Term Loan Credit Facility | LIBOR Rate | Minimum
Line of Credit Facility [Line Items]
Interest rate basis points of credit facility	1.00%
Term Loan Credit Facility | $200M Term Loan Credit Facility | Eurodollar
Line of Credit Facility [Line Items]
Interest rate basis points of credit facility	3.75%
Increase in basis points of credit facility	0.25%

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Long-Term Debt - Schedule of Maturities of Long-term Debt (Details) $ in Thousands	Dec. 31, 2017 USD ($)
Debt Disclosure [Abstract]
Debt maturities, repayment of principal in next twelve months	$ 2,957
Debt maturities, repayment of principal in year two	4,097
Debt maturities, repayment of principal in year three	2,000
Debt maturities, repayment of principal in year four	2,000
Debt maturities, repayment of principal in year five	2,000
Debt maturities, repayment of principal after year five	190,000
Partnership debt	$ 203,054

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Asset Retirement Obligations - Reconciliation of Total Reclamation Liability (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligations at beginning of period	$ 9,514	$ 8,711		$ 8,317
Additions to liabilities	207	373
Accretion expense	458	430	[1]	394	[1],[2]
Asset retirement obligations at end of period	$ 10,179	$ 9,514		$ 8,711

[1] Financial information has been recast to include the financial position and results attributable to Hi-Crush Whitehall LLC and Other Assets.

[2] Financial information has been recast to include the financial position and results attributable to Hi-Crush Blair LLC.

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Commitments and Contingencies - Narrative (Details)	12 Months Ended
	Dec. 31, 2017 USD ($) railcar	Dec. 31, 2016 USD ($)		Dec. 31, 2015 USD ($)		Mar. 15, 2017 USD ($)	Aug. 31, 2016 USD ($)
Long-term Purchase Commitment [Line Items]
Payments for non-delivery of minimum annual sand volumes	$ 0
Royalty expense	$ 19,091,000	$ 6,725,000		$ 13,660,000
Property value guarantees, sale period threshold	180 days
Property value guaranty purchases	$ 2,188,000
Rail car rental expense	$ 27,410,000	28,597,000		22,027,000
Expected number of additional leased railcars | railcar	700
Capital contributions to PropX	$ 7,168,000	10,232,000	[1]	$ 0	[1],[2]
Proppant Express Investments, LLC
Long-term Purchase Commitment [Line Items]
Lease expense, related party	1,577,000	124,000
Proppant Express Investments, LLC
Long-term Purchase Commitment [Line Items]
Maximum amount committed to equity method investment	$ 17,400,000
Maximum term to provide additional funds to equity method investment	18 months
Capital contributions to PropX	$ 7,168,000	$ 10,232,000
Minimum
Long-term Purchase Commitment [Line Items]
Initial term of contracted minimum sand volumes	1 year
Maximum
Long-term Purchase Commitment [Line Items]
Initial term of contracted minimum sand volumes	7 years
Hi-Crush Blair LLC
Long-term Purchase Commitment [Line Items]
Business acquisition, maximum contingent consideration to pay							$ 10,000,000
Hi-Crush Whitehall LLC and Other Assets
Long-term Purchase Commitment [Line Items]
Business acquisition, maximum contingent consideration to pay						$ 65,000,000

[1] Financial information has been recast to include the financial position and results attributable to Hi-Crush Whitehall LLC and Other Assets.

[2] Financial information has been recast to include the financial position and results attributable to Hi-Crush Blair LLC.

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Commitments and Contingencies - Schedule of Contractual Obligations (Details) $ in Thousands	Dec. 31, 2017 USD ($)
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
Operating leases, future minimum payments, next twelve months	$ 33,787
Operating leases, future minimum payments, due in two years	33,638
Operating leases, future minimum payments, due in three years	30,831
Operating leases, future minimum payments, due in four years	24,068
Operating leases, future minimum payments, due in five years	18,036
Operating leases, future minimum payments, due thereafter	16,670
Operating leases	157,030
Contractual Obligation, Fiscal Year Maturity Schedule [Abstract]
Minimum purchase commitments, due in twelve months	5,571
Minimum purchase commitments, due in second year	2,616
Minimum purchase commitments, due in third year	2,296
Minimum purchase commitments, due in fourth year	2,296
Minimum purchase commitments, due in fifth year	2,296
Minimum purchase commitments, due thereafter	1,871
Minimum purchase commitments	$ 16,946

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Commitments and Contingencies - Schedule of Contingent Consideration (Details) - USD ($) $ in Thousands		1 Months Ended
		Mar. 31, 2018	Dec. 31, 2017	Mar. 15, 2017	Aug. 31, 2016
Hi-Crush Blair LLC
Business Acquisition, Contingent Consideration [Line Items]
Original carrying fair value of contingent consideration liability					$ 5,000
Business acquisition, minimum contingent consideration to pay	[1]				5,000
Business acquisition, maximum contingent consideration to pay					$ 10,000
Business acquisition, current estimated fair value of contingent consideration			$ 7,226
Hi-Crush Whitehall LLC and Other Assets
Business Acquisition, Contingent Consideration [Line Items]
Original carrying fair value of contingent consideration liability				$ 14,000
Business acquisition, minimum contingent consideration to pay	[1]			20,000
Business acquisition, maximum contingent consideration to pay				$ 65,000
Business acquisition, current estimated fair value of contingent consideration			20,000
Minimum | Hi-Crush Blair LLC
Business Acquisition, Contingent Consideration [Line Items]
Sensitivity analysis of fair value of contingent consideration, impact of 10 percent change in assumptions			7,226
Minimum | Hi-Crush Whitehall LLC and Other Assets
Business Acquisition, Contingent Consideration [Line Items]
Sensitivity analysis of fair value of contingent consideration, impact of 10 percent change in assumptions			20,000
Maximum | Hi-Crush Blair LLC
Business Acquisition, Contingent Consideration [Line Items]
Sensitivity analysis of fair value of contingent consideration, impact of 10 percent change in assumptions			7,226
Maximum | Hi-Crush Whitehall LLC and Other Assets
Business Acquisition, Contingent Consideration [Line Items]
Sensitivity analysis of fair value of contingent consideration, impact of 10 percent change in assumptions			$ 20,000
Forecast | Hi-Crush Blair LLC
Business Acquisition, Contingent Consideration [Line Items]
Business acquisition, estimated future payment of contingent consideration		$ 5,000
Forecast | Hi-Crush Whitehall LLC and Other Assets
Business Acquisition, Contingent Consideration [Line Items]
Business acquisition, estimated future payment of contingent consideration		$ 20,000

[1] The Partnership anticipates payment of $5,000 and $20,000 for the 2017 measurement periods related to the Blair Contribution and the Whitehall Contribution, respectively, in March 2018 to our sponsor pending approval from the conflicts committee.

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Equity - Narrative (Details) - USD ($) $ / shares in Units, $ in Thousands					12 Months Ended
	Mar. 15, 2017	Mar. 03, 2017	Jan. 04, 2017	Aug. 31, 2016	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015		Oct. 17, 2017	Jun. 30, 2017
Class of Stock [Line Items]
Limited partners interest, units outstanding (in units)					89,009,188	63,668,244
Number of common units issued (in units)					23,575,000	19,550,000
Proceeds from equity issuances, net					$ 412,577	$ 189,037	[1]	$ 0	[1],[2]
Issuance of common units for an asset acquisition (in units)					3,438,789
Number of common units repurchased (in units)					2,030,163
Repurchase of common units					$ 20,000
Common unit aggregate offering price, maximum amount			$ 50,000
Target incentive distribution levels per unit, per quarter (usd per unit)					$ 0.54625
Incentive cash distributions to General Partner					100.00%
Weighted average potentially dilutive common units outstanding (in units)					1,382,733	0		191,890
Conversion of advances to Hi-Crush Proppants LLC				$ 120,950	$ 116,417	$ 120,950
Expense paid by sponsor on behalf of the Partnership					0	1,652	[1]	$ 2,787	[1],[2]
Limited Partner
Class of Stock [Line Items]
Repurchase of common units					20,000
General Partner and IDRs
Class of Stock [Line Items]
Net income (loss) allocated to holders of incentive distribution rights					$ 0	0		2,622
Minimum
Class of Stock [Line Items]
Incentive distribution rights, distribution levels in percentage					15.00%
Maximum
Class of Stock [Line Items]
Incentive distribution rights, distribution levels in percentage					50.00%
Hi-Crush Whitehall LLC and Other Assets
Class of Stock [Line Items]
Conversion of advances to Hi-Crush Proppants LLC	$ 116,417
Hi-Crush Blair LLC
Class of Stock [Line Items]
Expense paid by sponsor on behalf of the Partnership						$ 1,652		$ 2,787
Sponsor Owned Common Units
Class of Stock [Line Items]
Limited partners interest, units outstanding (in units)											20,693,643
Common Units
Class of Stock [Line Items]
Management and board of directors ownership interest in limited partner units					10.00%
Issuance of common units for an asset acquisition (in units)		3,438,789
Common Units | Limited Partner
Class of Stock [Line Items]
Repurchase of common units					$ 20,000
October 2017 Unit Repurchase Plan
Class of Stock [Line Items]
Repurchase of common units, authorized amount										$ 100,000
Repurchase of common units					$ 20,000
Repurchase of common units, average price including commissions (usd per unit)					$ 9.82
October 2017 Unit Repurchase Plan | Common Units
Class of Stock [Line Items]
Number of common units repurchased (in units)					2,030,163
Hi-Crush Partners LP Long-Term Incentive Plan
Class of Stock [Line Items]
Weighted average potentially dilutive common units outstanding (in units)					1,382,733			191,890
Potentially dilutive awards granted and outstanding excluded from diluted earnings per unit calculation (in units)						579,781

[1] Financial information has been recast to include the financial position and results attributable to Hi-Crush Whitehall LLC and Other Assets.

[2] Financial information has been recast to include the financial position and results attributable to Hi-Crush Blair LLC.

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Equity - Distributions (Details) - USD ($) $ / shares in Units, $ in Thousands											12 Months Ended
	Feb. 13, 2018	Jan. 17, 2018	Nov. 14, 2017	Oct. 16, 2017	Aug. 14, 2015	Jul. 21, 2015	May 15, 2015	Apr. 16, 2015	Feb. 13, 2015	Jan. 15, 2015	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Distribution Made to Limited Partner [Line Items]
Amount Declared Per Unit (usd per unit)											$ 0.35	$ 0	[1]	$ 1.15	[1],[2]
General Partner and IDRs
Distribution Made to Limited Partner [Line Items]
Payment to Holders of Incentive Distribution Rights			$ 0		$ 0		$ 1,311		$ 1,311		$ 0	$ 0		$ 1,311
Limited Partner
Distribution Made to Limited Partner [Line Items]
Amount Declared Per Unit (usd per unit)				$ 0.15		$ 0.475		$ 0.675		$ 0.6750
Payment to Limited Partner Units			$ 13,656		$ 17,555		$ 24,947		$ 24,947
Subsequent Event | General Partner and IDRs
Distribution Made to Limited Partner [Line Items]
Payment to Holders of Incentive Distribution Rights	$ 0
Subsequent Event | Limited Partner
Distribution Made to Limited Partner [Line Items]
Amount Declared Per Unit (usd per unit)		$ 0.20
Payment to Limited Partner Units	$ 17,809

[1] Financial information has been recast to include the financial position and results attributable to Hi-Crush Whitehall LLC and Other Assets.

[2] Financial information has been recast to include the financial position and results attributable to Hi-Crush Blair LLC.

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Equity - Weighted Average Limited Partner Units Outstanding (Details) - shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Equity [Abstract]
Weighted average limited partner units outstanding, basic (in units)	86,518,249	49,567,268	[1]	36,958,988	[1],[2]
Weighted average potentially dilutive common units outstanding (in units)	1,382,733	0		191,890
Weighted average limited partner units outstanding, diluted (in units)	87,900,982	49,567,268	[1]	37,150,878	[1],[2]

[1] Financial information has been recast to include the financial position and results attributable to Hi-Crush Whitehall LLC and Other Assets.

[2] Financial information has been recast to include the financial position and results attributable to Hi-Crush Blair LLC.

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Equity - Schedule of Net Income Attributable to Limited Partners (Details) - USD ($) $ / shares in Units, $ in Thousands					3 Months Ended										12 Months Ended
	Nov. 14, 2017	Aug. 14, 2015	May 15, 2015	Feb. 13, 2015	Dec. 31, 2017	Sep. 30, 2017	[1]	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	[2]	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Distribution Made to Limited Partner [Line Items]
Declared distributions to Limited Partner Units															$ 31,457	$ 0		$ 43,813
Assumed allocation of earnings (loss) in excess of distributions															51,077	(84,519)		(16,091)
Assumed allocation of net income (loss) to Limited Partners															$ 84,005	$ (81,313)		$ 28,265
Earnings (loss) per limited partner unit - basic (usd per unit)					$ 0.48	$ 0.33		$ 0.18	$ (0.07)	$ (0.11)	$ (0.21)	$ (0.26)	$ (1.39)		$ 0.97	$ (1.64)	[3]	$ 0.73	[3],[4]
Earnings (loss) per limited partner unit - diluted (usd per unit)															$ 0.96	$ (1.64)	[3]	$ 0.73	[3],[4]
Hi-Crush Blair LLC
Distribution Made to Limited Partner [Line Items]
Add back recast income (losses) attributable to assets contributed by the sponsor																$ (279)		$ 2,619
Hi-Crush Whitehall LLC and Other Assets
Distribution Made to Limited Partner [Line Items]
Add back recast income (losses) attributable to assets contributed by the sponsor															$ 1,471	3,485		(2,076)
Common Units
Distribution Made to Limited Partner [Line Items]
Declared distributions to Limited Partner Units															31,457	0		42,502
Assumed allocation of earnings (loss) in excess of distributions															51,077	(84,519)		(16,091)
Assumed allocation of net income (loss) to Limited Partners															84,005	(81,313)		26,954
Common Units | Hi-Crush Blair LLC
Distribution Made to Limited Partner [Line Items]
Add back recast income (losses) attributable to assets contributed by the sponsor																(279)		2,619
Common Units | Hi-Crush Whitehall LLC and Other Assets
Distribution Made to Limited Partner [Line Items]
Add back recast income (losses) attributable to assets contributed by the sponsor															1,471	3,485		(2,076)
General Partner and IDRs
Distribution Made to Limited Partner [Line Items]
Distributions made to holders of incentive distribution rights	$ 0	$ 0	$ 1,311	$ 1,311											0	0		1,311
Assumed allocation of earnings (loss) in excess of distributions															0	0		0
Assumed allocation of net income (loss) to General Partner and IDRs															$ 0	$ 0		$ 1,311

[1] The third quarter of 2017 includes $3,554 of other operating income related to a contract dispute that was subsequently resolved.

[2] The first quarter of 2016 includes a $33,745 impairment of goodwill. Refer to Note 15 for additional disclosure.

[3] Financial information has been recast to include the financial position and results attributable to Hi-Crush Whitehall LLC and Other Assets.

[4] Financial information has been recast to include the financial position and results attributable to Hi-Crush Blair LLC.

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Unit-Based Compensation - Narrative (Details) - USD ($) $ / shares in Units, $ in Thousands			1 Months Ended	12 Months Ended
	Nov. 15, 2018	Feb. 28, 2017	Jan. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Sep. 21, 2016
Common Units | Directors
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of common units issued to directors				29,148	103,377	6,344
Common Units | Subsequent Event | Directors
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of common units issued to directors			36,109
Unit Purchase Programs
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Discount of fair value on common units from the applicable election date		10.00%		15.00%
Issuance of units under Unit Purchase Programs		300,090
Weighted average purchase price of common units purchased under Unit Purchase Programs		$ 5.49
Unit Purchase Programs | Directors
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Accumulated contributions to Unit Purchase Program from directors				$ 438
Hi-Crush Partners LP Long Term Incentive Plan | Performance Phantom Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting period				3 years
Number of common unit of each award				1
Total compensation expense not yet recognized				$ 1,974
Weighted average remaining service period				1 year 7 months 13 days
Weighted average grant date fair value (in usd per unit)				$ 6.85	$ 15.94	$ 37.52
Hi-Crush Partners LP Long Term Incentive Plan | Performance Phantom Units | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage				0.00%
Hi-Crush Partners LP Long Term Incentive Plan | Performance Phantom Units | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage				200.00%
Hi-Crush Partners LP Long Term Incentive Plan | Time-Based Phantom Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting period				3 years
Number of common unit of each award				1
Total compensation expense not yet recognized				$ 7,521
Weighted average remaining service period				2 years 2 months 21 days
Weighted average grant date fair value (in usd per unit)				$ 8.94	$ 12.96	$ 34.09
Fair value of units vested				$ 714	$ 62	$ 42
Hi-Crush Partners LP Long Term Incentive Plan | Common Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of common units authorized under the Plan							4,064,035
Forecast | Unit Purchase Programs
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of common units anticipated to be purchased in the future (in units)	347,000

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Unit-Based Compensation - Performance Phantom Units (Details) - Hi-Crush Partners LP Long Term Incentive Plan - Performance Phantom Units - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Performance Phantom Units
Outstanding units at beginning of period	201,521
Granted units	184,019
Forfeited units	(39,399)
Outstanding units at end of period	346,141	201,521
Grant Date Weighted-Average Fair Value per Unit
Outstanding units at beginning of period (usd per unit)	$ 29.03
Granted (usd per unit)	6.85	$ 15.94	$ 37.52
Forfeited (usd per unit)	52.53
Outstanding units at end of period (usd per unit)	$ 14.56	$ 29.03

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Unit-Based Compensation - Time-Based Phantom Units (Details) - Hi-Crush Partners LP Long Term Incentive Plan - Time-Based Phantom Units - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Time-Based Phantom Units
Outstanding units at beginning of period	378,260
Vested units	(28,080)
Granted units	720,923
Forfeited units	(34,511)
Outstanding units at end of period	1,036,592	378,260
Grant Date Weighted-Average Fair Value per Unit
Outstanding units at beginning of period (usd per unit)	$ 16.40
Vested (usd per unit)	25.43
Granted (usd per unit)	8.94	$ 12.96	$ 34.09
Forfeited (usd per unit)	16.22
Outstanding units at end of period (usd per unit)	$ 10.97	$ 16.40

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Unit-Based Compensation - Total Compensation Expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Compensation Expense [Line Items]
Total compensation expense	$ 5,714	$ 2,620	$ 2,983
Performance Phantom Units
Compensation Expense [Line Items]
Total compensation expense	1,549	634	1,973
Time-Based Phantom Units
Compensation Expense [Line Items]
Total compensation expense	3,149	1,359	724
Director and other unit grants
Compensation Expense [Line Items]
Total compensation expense	499	474	273
Unit Purchase Programs
Compensation Expense [Line Items]
Total compensation expense	$ 517	$ 153	$ 13

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Related Party Transactions - Narrative (Details) - USD ($) $ in Thousands			12 Months Ended
	Mar. 15, 2017	Aug. 31, 2016	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Related Party Transaction [Line Items]
Due to sponsor			$ 12,399	$ 118,641	[1]
Conversion of advances to Hi-Crush Proppants LLC		$ 120,950	116,417	120,950
Hi-Crush Services LLC
Related Party Transaction [Line Items]
Management and administrative services			5,521	4,938		$ 5,260
Goose Landing, LLC
Related Party Transaction [Line Items]
Purchases from related parties			0			$ 2,754
Proppant Express Investments, LLC
Related Party Transaction [Line Items]
Purchases from related parties			6,593	1,566
Accounts payable, related party			1,273	1,553
Lease expense, related party			$ 1,577	$ 124
Hi-Crush Whitehall LLC and Other Assets
Related Party Transaction [Line Items]
Conversion of advances to Hi-Crush Proppants LLC	$ 116,417

[1] Financial information has been recast to include the financial position and results attributable to Hi-Crush Whitehall LLC and Other Assets.

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Impairments and Other Expenses - Narrative (Details) $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2016 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($) facility
Restructuring and Related Activities [Abstract]
Impairment of goodwill	$ 33,745	$ 0	$ 33,745	$ 0
Impairment of intangible assets		0	0	18,606
Property, Plant and Equipment [Line Items]
Impairment of idled administrative and transload facilities		0	0	6,186
Severance, retention and relocation		$ 40	$ 280	$ 571
Transload facilities and equipment
Property, Plant and Equipment [Line Items]
Number of idled facilities | facility				5
Rail and rail equipment
Property, Plant and Equipment [Line Items]
Number of idled facilities | facility				3

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Impairments and Other Expenses - Components of Impairments and Other Expenses (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Restructuring and Related Activities [Abstract]
Impairment of Goodwill	$ 33,745	$ 0	$ 33,745		$ 0
Impairment of Sand Supply Agreement		0	0		18,606
Impairment of idled administrative and transload facilities		0	0		6,186
Severance, retention and relocation		40	280		571
Exploration expenses		143	0		0
Abandonment of construction projects		460	0		256
Expiration of exclusivity agreements		222	0		40
Impairments and other expenses		$ 865	$ 34,025	[1]	$ 25,659	[1],[2]

[1] Financial information has been recast to include the financial position and results attributable to Hi-Crush Whitehall LLC and Other Assets.

[2] Financial information has been recast to include the financial position and results attributable to Hi-Crush Blair LLC.

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Segment Reporting - Narrative (Details)	12 Months Ended
	Dec. 31, 2017 segment
Segment Reporting [Abstract]
Number of operating segments	1

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Concentration of Credit Risk - Significant Customers Concentration Risk (Details) - Customer Concentration Risk - Sales Revenue, Net	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Customer A
Concentration Risk [Line Items]
Percentage of revenue accounted by customers			11.00%
Customer B
Concentration Risk [Line Items]
Percentage of revenue accounted by customers	26.00%	28.00%	26.00%
Customer C
Concentration Risk [Line Items]
Percentage of revenue accounted by customers	11.00%	17.00%	12.00%
Customer D
Concentration Risk [Line Items]
Percentage of revenue accounted by customers		14.00%
Customer E
Concentration Risk [Line Items]
Percentage of revenue accounted by customers		19.00%	19.00%

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Quarterly Financial Data (Unaudited) - Summary of Quarterly Financial Data (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended										12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017		Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016		Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Revenues	$ 216,456	$ 167,583	[1]	$ 135,220	$ 83,364	$ 67,297	$ 46,556	$ 38,429	$ 52,148	[2]	$ 602,623	$ 204,430	[3]	$ 339,640	[3],[4]
Gross profit (loss)	61,808	38,823	[1]	27,742	6,453	416	(57)	(1,262)	(7)	[2]	134,826	(910)	[3]	83,402	[3],[4]
Income (loss) from operations	50,384	32,479	[1]	18,524	(3,338)	(5,105)	(8,813)	(8,088)	(48,860)	[2]	98,049	(70,866)	[3]	41,848	[3],[4]
Net income (loss)	$ 43,178	$ 29,807	[1]	$ 16,380	$ (6,831)	$ (8,126)	$ (11,734)	$ (12,159)	$ (52,500)	[2]	$ 82,534	$ (84,519)	[3]	$ 27,722	[3],[4]
Earnings (loss) per limited partner unit - basic (usd per unit)	$ 0.48	$ 0.33	[1]	$ 0.18	$ (0.07)	$ (0.11)	$ (0.21)	$ (0.26)	$ (1.39)	[2]	$ 0.97	$ (1.64)	[3]	$ 0.73	[3],[4]
Impairment of goodwill									$ 33,745		$ 0	$ 33,745		$ 0
Other operating income		$ 3,554									$ 3,554	$ 0	[3]	$ 12,310	[3],[4]

[1] The third quarter of 2017 includes $3,554 of other operating income related to a contract dispute that was subsequently resolved.

[2] The first quarter of 2016 includes a $33,745 impairment of goodwill. Refer to Note 15 for additional disclosure.

[3] Financial information has been recast to include the financial position and results attributable to Hi-Crush Whitehall LLC and Other Assets.

[4] Financial information has been recast to include the financial position and results attributable to Hi-Crush Blair LLC.

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Subsequent Events - Narrative (Details) - USD ($) $ / shares in Units, $ in Thousands											12 Months Ended
	Feb. 13, 2018	Jan. 17, 2018	Nov. 14, 2017	Oct. 16, 2017	Aug. 14, 2015	Jul. 21, 2015	May 15, 2015	Apr. 16, 2015	Feb. 13, 2015	Jan. 15, 2015	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Subsequent Event [Line Items]
Distribution declared per limited partner unit (usd per unit)											$ 0.35	$ 0	[1]	$ 1.15	[1],[2]
Limited Partner
Subsequent Event [Line Items]
Distributions made to limited partner units			$ 13,656		$ 17,555		$ 24,947		$ 24,947
Distribution declared per limited partner unit (usd per unit)				$ 0.15		$ 0.475		$ 0.675		$ 0.6750
Limited Partner | Subsequent Event
Subsequent Event [Line Items]
Distributions made to limited partner units	$ 17,809
Distribution declared per limited partner unit (usd per unit)		$ 0.20
General Partner and IDRs
Subsequent Event [Line Items]
Distributions made to holders of incentive distribution rights			$ 0		$ 0		$ 1,311		$ 1,311		$ 0	$ 0		$ 1,311
General Partner and IDRs | Subsequent Event
Subsequent Event [Line Items]
Distributions made to holders of incentive distribution rights	$ 0

[1] Financial information has been recast to include the financial position and results attributable to Hi-Crush Whitehall LLC and Other Assets.

[2] Financial information has been recast to include the financial position and results attributable to Hi-Crush Blair LLC.

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Schedule II - Valuation and Qualifying Accounts - (Details) - Allowance for doubtful accounts - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Movement in Valuation Allowances and Reserves [Roll Forward]
Allowance for doubtful accounts, beginning balance	$ 1,549	$ 663	$ 984
Charged to costs and expenses	0	8,236	101
Deductions	(489)	(7,350)	(422)
Allowance for doubtful accounts, ending balance	$ 1,060	$ 1,549	$ 663