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EX-95.1 - EXHIBIT 95.1 - Hi-Crush Partners LPexhibit951-fy16.htm
EX-32.2 - EXHIBIT 32.2 - Hi-Crush Partners LPexhibit322-fy16.htm
EX-32.1 - EXHIBIT 32.1 - Hi-Crush Partners LPexhibit321-fy16.htm
EX-31.2 - EXHIBIT 31.2 - Hi-Crush Partners LPexhibit312-fy16.htm
EX-31.1 - EXHIBIT 31.1 - Hi-Crush Partners LPexhibit311-fy16.htm
EX-23.2 - EXHIBIT 23.2 - Hi-Crush Partners LPexhibit232-jtboydconsent20.htm
EX-23.1 - EXHIBIT 23.1 - Hi-Crush Partners LPexhibit231-pwcconsent2016.htm
EX-21.1 - EXHIBIT 21.1 - Hi-Crush Partners LPexhibit211-listingofsubsid.htm
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, 2016
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.)
 
 
Three Riverway, Suite 1350, Houston, Texas
77056
(Address of Principal Executive Offices)
(Zip Code)
Registrant’s telephone number, including area code (713) 980-6200
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
 
Name of each exchange on which registered
Common units representing limited partnership interests
 
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. þYes ¨No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. ¨Yes þNo
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. þYes ¨No
Indicate by check mark 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, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer    ¨
Accelerated filer    þ
Non-accelerated filer    ¨
Smaller reporting company    ¨
(Do not check if a smaller reporting company.)                    
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, 2016, 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 $459,499,010 based on the closing price of $13.07 per common unit on that date.
As of February 10, 2017, there were 63,697,392 common units outstanding.



HI-CRUSH PARTNERS LP
INDEX TO FORM 10-K
 
Page
PART I
Item 1. Business
Item 1A. Risk Factors
Item 2. Properties
PART II
PART III
PART IV
Item 16. Form 10-K Summary




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,” “assume,” “forecast,” “position,” “predict,” “strategy,” “expect,” “intend,” "hope," “plan,” “estimate,” “anticipate,” “believe,” “project,” “budget,” “potential,” 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 well site, which could be adversely affected by, among other things, logistics constraints, weather, or other delays at the transloading facility;
changes in prevailing economic conditions, including the extent of changes in natural gas, crude oil 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 and unusual or unfavorable geologic conditions;
changes in the price and availability of natural gas or electricity;
unanticipated ground, grade or water conditions;
reduction in the amount of water available for processing;
cave-ins, pit wall failures or rock falls;
inability to obtain necessary production equipment or replacement parts;
changes in the railroad infrastructure, price, capacity and availability, including the potential for rail line washouts;
changes in the price and availability of transportation;
availability of or failure of our contractors 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;
technical difficulties or failures;
fires, explosions or other accidents;
late delivery of supplies;
difficulty collecting receivables;
inability of our customers to take delivery;
difficulties in obtaining and renewing environmental permits;
facility shutdowns in response to environmental regulatory actions;
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;

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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 drilling basins 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 prior to August 16, 2012 refer to the business of Hi-Crush Proppants LLC, which is our accounting predecessor that contributed certain of its subsidiaries to Hi-Crush Partners LP on August 16, 2012 in connection with our initial public offering. Otherwise, those terms refer to Hi-Crush Partners LP and its subsidiaries. References in this Annual Report on Form 10-K to “Hi-Crush Proppants LLC,” “our predecessor” and “our sponsor” refer to Hi-Crush Proppants LLC.
Overview
Hi-Crush Partners LP (together with its subsidiaries, the “Partnership”) is an integrated producer, transporter, marketer and distributor of high-quality monocrystalline sand, a specialized mineral that is used as a proppant to enhance the recovery rates of hydrocarbons from oil and natural gas wells. Our reserves, which are located in Wisconsin, consist of "Northern White" sand, a resource that exists predominately in Wisconsin and limited portions of the upper Midwest region of the United States. The Partnership owns and operates a portfolio of sand facilities with on-site wet and dry plant assets, including direct access to major U.S. railroads for distribution to in-basin terminals. We own and operate a network of strategically located terminals and an integrated distribution system throughout North America, including our PropStreamTM integrated logistics solution, which delivers proppant into the blender at the well site.
Over the past decade, exploration and production companies have increasingly 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 wellbore. As a result, North American demand for proppant 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 and persisted at levels well below those experienced during the middle of 2014. As a result, the number of rigs drilling for oil and gas fell dramatically from the high levels achieved during third quarter of 2014. Due to uncertainty experienced over the past two years regarding the timing and extent of a recovery, exploration and production companies sharply reduced their drilling and completion activities in an effort to control costs. As a result, our customers faced uncertainty related to overall activity levels, and well completion activity was significantly below levels experienced in 2014 and 2015. The combination of these and other factors reduced proppant demand and pricing during 2016 significantly from the levels experienced during 2014. Proppant demand did not decline as significantly as the rig count and well completion activity might imply, though, due to the continuing trend of longer laterals and increasing use of sand per lateral foot in well completions. Given the marginal improvement in exploration and production activity during the fourth quarter of 2016 and the energy industry's outlook for 2017 activity levels, we expect the recent years' downward trend in well completion activity to reverse 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 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 acquisition of additional frac sand reserves, the development of new excavation and processing facilities and the development of new terminal facilities and logistics related assets. We expect to have the opportunity to acquire significant additional acreage and reserves currently owned by our sponsor, including the 1,447-acre facility with integrated rail infrastructure, located near Independence, Wisconsin and Whitehall, Wisconsin (the "Whitehall facility"), in addition to potential acquisitions from unrelated third parties.
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, 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"), for total cash consideration of $261.8 million and 3,750,000 newly issued convertible Class B units in the Partnership (the “Augusta Contribution”). Subsequently on August 15, 2014, our sponsor, as the sole owner of our Class B units, elected to convert all of the 3,750,000 Class B units into common units on a one-for-one basis.

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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 shales.
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 earnout consideration (the "Blair Contribution"). The Partnership completed the acquisition of the Blair facility on August 31, 2016.
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 consist entirely of “Northern White” sand exceeding American Petroleum Institute (“API”) minimum specifications. Analysis of our sand by independent third-party testing companies indicates that it demonstrates characteristics in excess of API minimum specifications with regard to crush strength (ability to withstand high pressures), turbidity (low levels of contaminants) and roundness and sphericity (facilitates hydrocarbon flow or conductivity).
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, 2016, contained 76.4 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 41 years as of December 31, 2016.
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. It also enables us to accommodate unit trains, which significantly increases our efficiency in meeting our customers’ frac sand transportation needs. Unit trains, typically 80 rail cars in length or longer, are dedicated trains chartered for a single delivery destination. Generally, unit trains receive priority scheduling and do not switch cars at various intermediate junctions, which results in a more cost-effective and expedited method of shipping than the standard method of rail shipment.
Augusta Facility
The Augusta facility, as of December 31, 2016, contained 40.9 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 14 years as of December 31, 2016. During September 2016, we resumed production at the Augusta facility, which was previously idled in October 2015 as a result of market conditions.
All of the product from the Augusta facility is shipped by rail from approximately 28,800 feet of track that connects our facility to a Union Pacific Railroad mainline. These rail spurs and the capacity of the associated product storage silos allow us to accommodate a large number of rail cars, including unit trains.
Blair Facility
The Blair facility, as of December 31, 2016, contained 117.7 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 41 years as of December 31, 2016.
All of the product from the Blair facility is shipped by rail from approximately 43,000 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.

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Sponsor's Whitehall Facility
Our sponsor's Whitehall facility, as of December 31, 2016, contained 80.7 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. During 2016, the Partnership purchased 413,781 tons from our sponsor's Whitehall facility. 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 28 years as of December 31, 2016. As a result of market conditions, the Whitehall facility was temporarily idled during the second quarter of 2016 and is expected to resume operations in late March or early April 2017.
All of the product from the Whitehall facility is shipped by rail from approximately 30,000 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.
Terminal Facilities
As of December 31, 2016, we own or operate 11 terminal locations throughout Colorado, Pennsylvania, Ohio, New York and Texas, of which three are temporarily idled and six are capable of accommodating unit trains. Our terminals include approximately 74,000 tons of rail storage capacity and approximately 120,000 tons of silo storage capacity. Each terminal location is strategically positioned in the shale plays to facilitate our customers' operations. Our terminals include rail-to-truck and rail-to-storage capabilities and serve as the base for a 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 production facilities in Wisconsin. As of December 31, 2016, we leased or owned 4,200 railcars used to transport our sand from origin to destination and managed a fleet of approximately 1,358 additional railcars dedicated to our facilities by our customers or the Class I railroads.
PropStream Operations
In September 2016, the Partnership and other partners formed Proppant Express Investments, LLC (“PropX”), which was established to develop critical last-mile logistics equipment for the proppant industry. In October 2016, the Partnership announced the successful pilot test of its PropStream integrated logistics solution, which involves loading proppant at in-basin terminals into PropX containers before being transported by truck to the well site. The containers utilize intermodal container chassis or standard flatbeds for transportation, resulting in significant savings both in terms of up-front and ongoing operations costs versus widely-used pneumatic equipment. PropStream allows for increased transportation efficiency and a reduction in supply chain related congestion at well sites, lowering the number of trucks required per job and meaningfully reducing or eliminating demurrage costs.
At the well site, the proprietary conveyor system (“PropBeast™”) significantly reduces noise and dust emissions due to its enclosed environment. By reducing particulate matter emissions from sand operations at the well site by more than 90% versus the widely-used pneumatic equipment alternative. Our PropStream integrated logistics solution is designed to provide a viable solution to meet 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, 2016, we owned 6 PropBeast conveyors and leased 300 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 cash distributions per unit 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 with a significant variable component for the excavation and processing of our sand. Due to the shallow overburden at our and our sponsor's facilities, we are able to use surface mining equipment, and dredging at our Wyeville facility, in our operations, which provides for a lower cost structure than underground mining operations. Our mining operations are subcontracted at a fixed cost per ton excavated, subject to a diesel fuel surcharge. 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 and minimizes the reduction in sand quality due to handling.

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Long-lived, high quality reserve base. Our Wyeville, Augusta and Blair facilities and our sponsor's Whitehall facility contain approximately 315.7 million tons of proven recoverable saleable frac sand reserves as of December 31, 2016, based on third-party reserve reports by John T. Boyd, and have an implied average reserve life of 30 years, assuming production at the rated capacity of each facility. These reserves consist of high quality Northern White frac sand. Analysis by independent third-party testing companies indicates that our sand demonstrates characteristics exceeding API specifications with regard to crush strength, turbidity and roundness and sphericity. As a result, our raw frac sand is particularly well suited for use in the hydraulic fracturing of unconventional oil and natural gas wells.
Intrinsic logistics and infrastructure advantage. The strategic location and logistics capabilities of our Wyeville, Augusta and Blair facilities and our sponsor's Whitehall facility enable us to serve all major U.S. and Canadian oil and natural gas producing basins. At our Wyeville and Augusta facilities, our on-site transportation assets include approximately 32,000 feet and 28,800 feet, respectively, of track off a Union Pacific Railroad mainline. The on-site transportation assets at our Blair facility and our sponsor's Whitehall facility include on-site rail yards that contain approximately 43,000 feet and 30,000 feet, respectively, of track off a Canadian National Railroad mainline. All of our and our sponsor's facilities are capable of accommodating unit trains, allowing our customers to receive priority scheduling, expedited delivery and a more cost-effective shipping alternative. Our logistics capabilities enable efficient loading of sand and minimize rail car turnaround times at the facilities. We expect to acquire or develop similar logistics capabilities at any facilities we own in the future. We believe we are one of the few frac sand producers with facilities initially designed to deliver frac sand exceeding API specifications to all of the major U.S. oil and natural gas producing basins by on-site rail facilities, including on-site storage capacity accommodating unit trains.
Strategically located terminal facilities. We operate through an extensive logistics network of rail-based terminals that we own strategically located throughout Colorado, Pennsylvania, Ohio, New York and Texas, as well as facilities owned and operated by third parties, to serve our customers' operations in North America's shale and other unconventional oil and natural gas plays. Many of our terminals are capable of handling unit trains, further reducing the cost of delivered sand for our customer. Our distribution network allows us to better service our customers’ short-notice needs in these basins, and at a lower price, and provide our customers with solutions to the logistical challenges presented by the large volume of sand typically required for each fracturing job.
Developing “last mile” capabilities. Our investment in PropX and the development of our PropStream integrated logistics solution expand the reach and delivery of frac sand directly to our customers’ usage points, while leveraging our logistics infrastructure advantage and utilizing our strategically located terminal facilities. The addition of “last mile” capabilities to our portfolio of services is aligned with our goals of delivering frac sand from the mine to the well more efficiently, expanding our potential customer base, and positioning us deeper into the sand supply chain.
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 monthly volume requirements for customers and have an average remaining contractual term of 2.9 years. In 2015, as a result of the market dynamics existing during the year, and continuing in 2016, we began providing market-based pricing to our contract customers and/or make-whole waivers in certain circumstances in exchange for, among other things, additional term and/or volume. We believe our long-term relationships with our customers provide us with a stable base of 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 development and accretive acquisitions and, together with members of our board of directors, are strongly incentivized to profitably and prudently grow our business and cash flows through their 13% direct and indirect ownership interest in our limited partnership units, and their 39% interest in our sponsor, which owned 20,693,643 common units and incentive distribution rights as of February 10, 2017.

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Business Strategies
Our primary business objectives are to provide capital appreciation and pay cash distributions per unit over time. We intend to accomplish this objective by executing the following strategies:
Capitalizing on compelling industry fundamentals. We intend to continue to position ourselves as a leading producer, transporter, marketer and distributor of high quality frac sand, as we believe the frac sand market offers attractive growth fundamentals over the long-term. The innovations in horizontal drilling in the various North American shales and other unconventional oil and natural gas plays has resulted in greater demand for frac sand per well and per stage. The long-term growth in sand demand is underpinned by continued horizontal drilling, increasing proppant use per well and cost advantages over other proppant types. The proppant use per well has continued to increase even in the face of depressed hydrocarbon prices. We believe increases in frac sand supply will be constrained by the difficulty in finding reserves that meet or exceed API technical specifications in contiguous quantities large enough to justify the capital investment required and overcome the challenges associated with successfully obtaining the necessary local, state and federal permits required for operations.
Building on our position as a low cost provider. We seek to maintain and improve our position as a low cost provider of sand. Our plant operations have been strategically designed to provide low per-unit production costs with a significant variable component for the excavation and processing of our sand. We will continue to analyze and pursue organic expansion efforts that will similarly allow us to cost-effectively optimize our existing assets. In addition, we seek to identify and evaluate terminal sites to expand our geographic footprint allowing us to enhance our distribution network and ensure that sand is available to meet the in-basin needs of our customers. Through a combination of our low cost production, our network of owned and operated terminals or third-party operated sites and our PropStream integrated logistics solution, we expect to find ways to reduce our customers' cost of sand delivered to the blender at the well site. We will continue to analyze and pursue third-party acquisition opportunities that would similarly allow us to cost-effectively expand our geographic footprint, 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 cash flows under long-term contracts with the major pressure pumping service providers who generally are our customers. We believe this business model serves as the foundation for our ability to serve our customers, while providing the product that is a critical component to the well completion service. 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 well site.
Pursuing accretive acquisitions from our sponsor and third parties. In June 2013, we acquired D&I, enabling us to operate through an extensive logistics network of rail-based terminals now strategically located throughout Colorado, Pennsylvania, Ohio, New York and Texas. In January 2013 and April 2014, the Partnership entered into contribution agreements with our sponsor to acquire substantially all of the equity interests in our sponsor’s Augusta facility. On August 9, 2016, the Partnership entered into a contribution agreement with our sponsor to acquire all of the outstanding membership interests in Blair. We expect to continue pursuing accretive acquisitions of frac sand facilities from our sponsor, including the Whitehall facility, as well as third-party frac sand production 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 and that provide or would accommodate the development and construction of rail or other 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 debt maturities and financing needs. As of February 10, 2017, our senior secured term loan facility that permits aggregate borrowings of $200.0 million was fully drawn with a $194.5 million balance outstanding and we had $66.2 million of undrawn borrowing capacity ($75.0 million, net of $8.8 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 2016, we successfully completed three public offerings for a total of 19,550,000 common units for aggregate net proceeds of approximately $189.0 million. 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. 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.

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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, which is the product we produce, resin-coated sand and manufactured ceramic beads.
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, and low turbidity (low levels of contaminants). Oil and gas producers generally require that frac sand used in their drilling and completion processes meet API specifications.
Raw frac sand can be further delineated into two main types: Northern White and Brady Brown. Northern White, which is the type of frac sand we produce, is known for its high crush strength, low turbidity, roundness and sphericity and monocrystalline grain structure. Northern White frac sand historically has commanded premium prices relative to Brady Brown. Brady Brown is sometimes preferred due to its proximity to shale basins, particularly the Permian basin and Eagle Ford shale, and, therefore, lower costs due to reduced logistics costs. Northern White has historically experienced the greatest market demand relative to supply, due both to its superior physical characteristics and the fact that it is a limited resource that exists predominately in Wisconsin and other limited parts of the upper Midwest region of the United States. However, even within this superior class of Northern White sand, its quality can vary significantly across deposits due to the differing geological processes that formed the various Northern White reserves.
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.
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.
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.

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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 there are 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 size 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.
Frac Sand Extraction, Processing and Distribution
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. After extraction, the raw frac sand is washed with water to remove fine impurities such as clay and organic particles. The final steps in the production process involve the drying and sorting of the raw frac sand according to mesh size.
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, including by unit train particularly 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 from our Wyeville and Augusta facilities is shipped by rail from on-site rail yards off a Union Pacific Railroad mainline. All of the product from our Blair facility and our sponsor's Whitehall facility is shipped by rail from on-site rail yards off a Canadian National Railroad mainline. The length of our 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. They also enable us to accommodate unit trains, which significantly increases our efficiency in meeting our customers’ frac sand transportation needs.
Designing and using an optimized logistics system is a key strategy for many proppant suppliers, including us, to reduce transportation costs and thereby the final proppant cost for end users. As locating proppant production close to key markets is not always possible, proppant suppliers will often have terminals in regions that they serve.  The ability to deliver sand shorter distances with fewer intermediate steps is instrumental in remaining cost competitive or gaining cost advantages.  Proppants are moved from the production site by rail or barge to transload or storage facilities.  From there, they are typically transported by truck to the well site.  Strategically locating transload facilities can therefore reduce the amount of conveyance by truck, which is typically the most expensive mode of transport. Use of containerized storage systems for transportation of proppant from the transload facilities to the well site allows for a reduction in supply chain related congestion at the well site, also offering a reduction in overall transportation costs of proppant for the end users.
Demand Trends
Demand growth for frac sand and other proppants is primarily due to 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. Despite depressed levels of activity in 2015 and throughout most of 2016 that lowered demand for proppant, we believe that demand for proppant will continue to grow 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 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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Furthermore, recent growth in demand for raw frac sand has outpaced growth in demand for other types of proppants, and industry analysts predict that this trend will continue. As well completion costs have increased as a proportion of total well costs, operators have increasingly looked for ways to improve per well economics by lowering costs without sacrificing production performance. To this end, over the last few years, the oil and natural gas industry has been shifting increasingly away from the use of higher-cost proppants, such as ceramics or resin coated sand, and more towards more cost-effective proppants, such as raw frac sand.
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;
the difficulty of securing contiguous frac sand reserves large enough to justify the capital investment required to develop a processing facility;
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.
Many announced expansions or greenfield projects were significantly delayed or canceled 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. In addition, several existing facilities were temporarily or permanently idled.
Commencing production at facilities previously idled can require 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 many idled facilities will re-enter the market until frac sand pricing has reached a sustained and higher level to incentivize the investment.
Pricing
Spot market prices for frac sand have declined dramatically from the levels experienced in 2014, as sand producers, particularly those with excess inventories, substantially discounted sand pricing in order to sell product in a lower demand environment. Pricing continued its decline throughout 2015 and continued in 2016, but began to stabilize in the third quarter of 2016 and increase in the fourth quarter of 2016, although remaining near historically low levels. While the outlook for pricing of raw frac sand in 2017 is uncertain, 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 in the first quarter of 2017 and is likely to be more favorable in 2017.
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 some of North America’s largest providers of pressure pumping services or their subsidiaries. For the year ended December 31, 2016, sales to each of Halliburton Company ("Halliburton"), Liberty Oilfield Services ("Liberty"), U.S. Well Services, LLC ("US Well") and Weatherford International Ltd. ("Weatherford") accounted for greater than 10% of our total revenues. In the fourth quarter of 2016, Weatherford made the decision to idle its U.S. pressure pumping business. As of February 10, 2017, the contractual relationship with Weatherford remains in place.

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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, 2016, we generated 84% 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 2017 and future years. As of January 1, 2017, our long-term contracts have an average remaining contractual term of 2.9 years and with remaining terms ranging from 8 to 55 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.
In 2015, as a result of the market dynamics existing during the year and continuing in 2016, we began providing 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. We continue to engage in discussions and may continue to deliver sand at prices or at volumes below those provided for in our existing contracts. In addition, 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. In December 2015, we received a settlement payment of $22.5 million for past and future obligations under a customer contract; $10.2 million of this settlement was recognized as revenue related to make-whole payments.
Our long-term customer contracts also contain penalties for our non-performance. If we are unable to deliver contracted volumes within three months of contract year end, or otherwise arrange for delivery from a third party, we are 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 also have the ability to supply our customers from facilities owned by our sponsor and third party facilities. We believe our levels of inventory combined with our cure period, generally three months after contract year end, 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 have sold 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 or our sponsor's production facilities, we can purchase, and have purchased in the past, a certain amount of frac sand from various third parties for sale to our customers. During the years ended December 31, 2016, 2015 and 2014, the Partnership purchased 413,781, 1,603,875 and 781,478 tons, respectively, from our sponsor's Whitehall facility and other third parties. 
Production Operations
Excavation Operations
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. The excavation process involves clearing vegetation and trees overlying the proposed mining area, with limited blasting processes conducted at our Augusta and Blair facilities and our sponsor's Whitehall facility. 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 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 wet plants operate for seven to eight months per year due to the limitations arising from sustained freezing temperatures during winter months. However, when the wet plants are operating they 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 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
All of the product sold from our Wyeville and Augusta facilities is shipped by rail from approximately 32,000 feet and 28,800 feet, respectively, of track that connects our facilities to a Union Pacific Railroad mainline. All of the product sold from our Blair facility and our sponsor's Whitehall facility is shipped by rail from approximately 43,000 feet and 30,000 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. We believe our production facilities are some of the first frac sand facilities in the industry initially designed to accommodate large scale rail and unit train logistics, which requires sufficient acreage, loading facilities and rail spurs.
Logistics capabilities of frac sand producers are important to our customers, who focus on both the reliability and flexibility of product delivery. Because our customers generally find it impractical to store frac sand in large quantities near their job sites, they seek to arrange for product to be delivered where and as needed, which requires predictable and efficient loading and shipping of product. The integrated nature of our logistics operations and our multiple rail spurs enable us to handle railcars for multiple customers simultaneously, minimizing the number of days required to successfully load shipments, even at times of peak activity, and avoid the use of trucks and minimize transloading within the facilities. At the same time, we believe our ability to ship from all of our facilities using unit trains differentiates us from most other frac sand producers that ship using manifest, or mixed freight, trains, which may make multiple stops to switch cars before delivering cargoes, or transport their products by truck or barge. In addition, unlike some competitors, our processing and rail loading facilities are located on-site, which eliminates the requirement for on-road transportation, lowers product movement costs and minimizes any reduction of sand quality due to increased handling. Together, these advantages provide our customers with a reliable and efficient delivery method from our facility to each of the major U.S. oil and natural gas producing basins, and allow us to take advantage of the increasing demand for such a delivery method.
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 well site 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 solution involves loading proppant at in-basin terminals into PropX containers before being transported by truck. The 8-foot cubic containers can each transport up to 33,000 pounds of proppant and, depending on Department of Transportation 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 both in terms of up-front and ongoing operations costs versus widely-used pneumatic equipment.  PropStream allows for increased transportation efficiency and a reduction in supply chain related congestion at well sites, lowering the number of trucks required per job and meaningfully reducing or eliminating demurrage costs.

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At the well site, the PropBeast conveyor system significantly reduces noise and dust emissions due to its enclosed environment.  PropBeast conveyors are capable of transferring up to approximately 60,000 pounds of proppant per minute into blender hoppers while reducing particulate matter emissions from sand operations at the well site by more than 90% versus the widely-used pneumatic equipment alternative. Our PropStream integrated logistics solution is designed to provide a viable solution to meet 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.
Competition
There are numerous large and small producers in all sand producing regions of the United States with which we compete. Our main competitors include:
U.S. Silica Holdings, Inc. (NYSE: SLCA)
Unimin Corporation
Fairmount Santrol Holdings, Inc. (NASDAQ: FMSA)
Badger Mining Corporation
Emerge Energy Services LP (NYSE: EMES)
Smart Sand, Inc. (NASDAQ: SND)
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 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 board of directors, whom currently have a 39% membership interest. Our sponsor’s lead investor is Avista Capital Partners ("Avista"), a leading private equity firm with significant investing and operating expertise in the energy industry. Founded in 2005 by senior investment professionals who worked together at DLJ Merchant Banking Partners (“DLJMB”), 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. The energy team at Avista is comprised of experienced professionals and industry executives with relevant expertise in the energy sector. Avista principals have led over $3.5 billion in equity investments in energy companies while at Avista and DLJMB, including Basic Energy Services, Inc., Brigham Exploration Company, Copano Energy, L.L.C., Seabulk International, Inc., and joint-ventures with Carrizo Oil & Gas, Inc.
Our Sponsor’s Assets
Our sponsor initially developed and constructed the Wyeville, Augusta and Blair facilities prior to their contribution or sale to the Partnership. The sponsor currently owns the Whitehall facility, completed in September 2014 and the remaining 2% interest in Augusta. As a result of market conditions, the Whitehall facility was temporarily idled during the second quarter of 2016 and is expected to resume operations in late March or early April 2017.
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, 20,693,643 common units, 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 expect to have the opportunity to make additional acquisitions directly from our sponsor in the future, including the Whitehall facility described above, our sponsor is under no obligation to accept any offer we make, and may, following good faith negotiations with us, sell the 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. Since the commencement of operations at its Whitehall facility in 2014, however, our sponsor has not been competing directly with us for new and existing customers; instead, our sponsor has sold sand at favorable pricing from its Whitehall facility to us for sale by us to our customers under our long-term contracts and in the spot market. Our sponsor may develop additional frac sand excavation and processing facilities in the future, which may compete with us. While we expect that our management team, which also manages our sponsor’s retained assets, and our sponsor will allocate new and existing customer contract volumes between us and our sponsor in a manner that balances the interests of both parties, they are under no obligation to do so.

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Our Management and Employees
We are managed and operated by the board of directors and executive officers of our general partner, Hi-Crush GP LLC, 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 without its consent, because our general partner and its affiliates own a sufficient number of units. 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.
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, 2016, Hi-Crush Proppants LLC and its wholly owned subsidiaries had 288 employees. In addition, we contract our excavation operations to a third party 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.

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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 EPA or the Wisconsin Department of Natural Resources ("Wisconsin DNR"), 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.
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, 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 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.

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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 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 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 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.
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
Production Facilities
We operate our and our sponsor's facilities under a number of federal, state and local authorizations.
Our 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 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 production facilities are currently covered by WPDES general construction permits for various projects.
Our 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.

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Our mining operations are subject to the conditions of nonmetallic mining permits granted and administered by either the County or City 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. 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.

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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
We may not have sufficient cash from operations following the establishment of cash reserves and payment of costs and expenses, including cost reimbursements to our general partner and its affiliates, to enable us to pay a distribution to our unitholders.
In October 2015, we announced the suspension of our distribution. We may not have sufficient cash each quarter to pay a distribution. The amount of cash we can distribute on our common units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on the following factors, some of which are beyond our control:
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 well site, which could be adversely affected by, among other things, logistics constraints, weather, or other delays at the transloading facility;
changes in prevailing economic conditions, including the extent of changes in natural gas, crude oil 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 and unusual or unfavorable geologic conditions;
changes in the price and availability of natural gas or electricity;
unanticipated ground, grade or water conditions;
reduction in the amount of water available for processing;
cave-ins, pit wall failures or rock falls;
inability to obtain necessary production equipment or replacement parts;
changes in the railroad infrastructure, price, capacity and availability, including the potential for rail line washouts;
changes in the price and availability of transportation;
availability of or failure of our contractors 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;
technical difficulties or failures;
fires, explosions or other accidents;
late delivery of supplies;
difficulty collecting receivables;
inability of our customers to take delivery;
difficulties in obtaining and renewing environmental permits;
facility shutdowns in response to environmental regulatory actions;
changes in laws and regulations (or the interpretation thereof) related to the mining and hydraulic fracturing industries, silica dust exposure or the environment;

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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 drilling basins in which we and our customers operate.
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, including any drop-down acquisitions from our sponsor;
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 long-term 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 natural gas and oil exploration, development and production, and more specifically, the number of natural gas and oil wells completed in geological formations where sand-based proppants are used in hydraulic fracturing treatments and the amount of frac sand customarily used in the completion of such wells.
Beginning in August 2014 and continuing through the second quarter of 2016, oil and natural gas producers’ expectations for lower market prices for oil and natural gas, as well as the limited availability of capital for operating and capital expenditures, has caused them to curtail spending and future changes in oil and natural gas prices may cause them to further curtail spending, thereby reducing hydraulic fracturing activity and the demand for frac sand. 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 natural gas and oil prices would generally depress the level of natural gas and oil exploration, development, production and well completion activity, which could result in a corresponding decline in the demand for the frac sand we produce. 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 volumes, or be forced to reduce our sales prices, any of which would reduce the amount of cash we generate.
In addition, the price we receive for sales of our frac sand may be impacted by short term fluctuations in the market for frac sand, and any negative fluctuations in this market could have an adverse effect on our results of operations and cash flows.

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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 Northern White frac sand, the sole product we produce and sell, to other raw frac sand, such as brown sand, 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, consistency and quality of product, site location, distribution and logistics capabilities, customer service, and reliability of supply and breadth of product offering.
We compete with large, national producers such as U.S. Silica Holdings, Inc., Unimin Corporation and Fairmount Santrol Holdings, Inc., and others. Our larger competitors may have greater financial and other resources than we do, may develop technology superior to ours or may have production 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 smaller, regional 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. We may not be able to compete successfully against either our larger or smaller competitors in the future, and competition could have a material adverse effect on our business, financial condition, results of operations and cash flows.
If we are unable to make acquisitions on economically acceptable terms, 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 increase distributions to unitholders is dependent on our ability to make acquisitions that result in an increase in our cash available for distribution per unit. If we are unable to make acquisitions from third parties, including from our sponsor and its affiliates, because we are unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts, 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. 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.
If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and unitholders will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.

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We have entered into a Revolving Credit Agreement and senior secured term loan facility which contain restrictions and financial covenants that may restrict our business and financing activities.
Our Revolving Credit Agreement and senior secured term loan 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 senior secured term loan facility restrict, and potentially 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 that allows distributions to unitholders up to 50% of quarterly distributable cash flow after quarterly debt payments on the term loan, establishes a maximum EBITDA loss for the six months ending March 31, 2017 and provides for an "equity cure" that can be applied to EBITDA covenant ratios for 2017 and all future periods. Additionally, our Revolving Credit Agreement and senior secured term loan 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;
enter into transactions with affiliates;
enter into sale lease back transactions.
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 senior secured term loan 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 senior secured term loan facility are secured by substantially all of our assets and if we are unable to repay our indebtedness as required under these facilities, the lenders could seek to foreclose on our assets.
Our long-term unsecured debt is currently rated by Standard and Poor’s ("S&P") and Moody's Investors Service Inc. ("Moody's"). As of February 10, 2017, the credit rating of the Partnership’s senior secured term loan credit facility was B from Standard and Poor’s and Caa1 from Moody’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, senior secured term loan facility and other notes payable. As of December 31, 2016, we had $201.2 million of debt outstanding, with an effective interest rate of 4.62%. 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 $0.9 million per year. As a result of this variable interest rate debt, our financial condition could be adversely affected by increases in interest rates.
The majority of our sales are generated under contracts with oil field service company customers. 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, 2017, we were contracted to sell raw frac sand under long-term supply agreements to customers with remaining terms ranging from 8 to 55 months. During 2016, more than 78% of our volumes were earned from four of our customers.

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Some of our customers have exited or could exit the pressure pumping business or 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.
In 2015, as a result of the market dynamics existing during the year and continuing in 2016, we began providing market-based pricing to our contract customers and/or make-whole waivers, in certain circumstances in exchange for, among other things, additional term and/or volume. Because we continue to engage in discussions with our customers, the nature, extent and duration of these pricing discounts and make-whole waivers are not certain and we may deliver sand at prices or at volumes below those provided for in our existing contracts. In addition, 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 and 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 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.
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 our long-term contracts are subject to annual fixed price escalators.
The 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 having similar characteristics as the raw frac sand we produce could make it more difficult for us to renew or replace our existing contracts on favorable terms, or at all.
We believe that the supply of raw frac sand had not kept pace with the increasing demand for raw frac sand until recently. If significant new reserves of raw frac sand are discovered and developed, and those frac sands have similar characteristics to the raw frac sand we produce, we may be unable to renew or replace our existing contracts at favorable pricing, or at all. Specifically, if high quality 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.

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Our expansion or modification of existing assets, or the construction of new assets, may not result in revenue increases and may be subject to regulatory, environmental, political, legal and economic risks, which could adversely affect our results of operations and financial condition.
The construction of 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 able 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. In addition, the construction of additions to our existing assets may require us to increase the size of our railcar fleet to support transportation of additional volumes. We may be unable to increase the size of our fleet to capitalize on other expansion or modification opportunities. Additionally, it may become more expensive for us to increase the size of our railcar fleet in-line with additional capacity, which may adversely impact our cash flows.
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, senior secured term loan 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 Wisconsin production facilities located in Wyeville, Augusta and Blair and our sponsor's Wisconsin production facility located near Whitehall. 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.
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

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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 renewed or received 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 in Wisconsin, 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.
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.
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.

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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.
During September 2016, the Partnership resumed production at the Augusta facility, which was previously idled in October 2015 as a result of market conditions. Our sponsor's Whitehall facility was temporarily idled during the second quarter of 2016.
If we idle our production facilities for a long period of time or close the 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 13% of our total production costs during the year ended December 31, 2016. 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 few 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 our 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 severe weather conditions. Severe weather conditions may affect our customers’ operations, thus reducing their need for our products, 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.

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In addition, severe winter weather conditions impact our operations by causing us to halt our excavation and wet plant related production activities during the winter months. During non-winter months, we excavate excess sand to build a washed sand stockpile that feeds the dry plant, which continues to operate during the winter months. 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.
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 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 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.
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.

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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 utilize third party contractors and there may be a shortage of skilled labor. If the shortage of experienced skilled labor continues or worsens, we may find it difficult to renew or replace third party contractors, and we may be unable to 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.
We face distribution and logistical 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 logistical 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 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 logistical 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 distribution 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.

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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 are not 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.
Continued downturn in business could result in potential impairment of intangible assets.
Beginning in August 2014 and continuing through the second quarter of 2016, global crude oil and natural gas prices, particularly crude oil, declined dramatically and persisted at levels well below those experienced during the middle of 2014. This decrease in commodity prices has had, and could continue to have, a negative impact on industry drilling and well completion activity, which affects the demand for frac sand.  Should energy industry conditions further deteriorate, there is a possibility that intangible assets may be impaired in a future period.  Any resulting non-cash impairment charges to earnings may be material. Specific uncertainties affecting our estimated fair value include the impact of competition, the prices of frac sand, future overall activity levels and demand for frac sand, the activity levels of our significant customers, and other factors affecting the rate of our future growth. These factors will continue to be reviewed and assessed going forward. Additional adverse developments with regard to these factors could have a negative impact on our fair value.
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.
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. 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. Our insurance coverage for cyber attacks may not be sufficient to cover all the losses we may experience as a result of such cyber attacks.

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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.
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.

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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 well sites. 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.
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.

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Our inability to acquire, maintain, or renew necessary financial assurances related to the reclamation and restoration of mining property could have a material adverse effect on our business, financial condition, and results of operations.
Risks Relating to our Structure
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;
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. In particular, our sponsor’s Whitehall facility could compete with us for new and existing frac sand customers.

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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 distribute quarterly on all of 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.
On October 26, 2015, our general partner's board of directors announced the temporary suspension of our quarterly distribution to common unitholders in order to conserve cash and preserve liquidity.
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 competes with us, and other affiliates of our general partner have the ability to compete with us.
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 investments in entities that acquire, own and operate frac sand excavation and processing facilities and may make additional investments 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. In addition, our sponsor owns the Whitehall facility through an entity that could compete with us and we expect that it will acquire interests in additional entities that may compete with us. 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 and amended customer contracts to us before offering them to our sponsor, which could have a material adverse impact on our ability to renew or replace existing customer contracts on favorable terms or at all.
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 Revolving Credit Agreement allows distributions to unitholders up to 50% of quarterly distributable cash flow after quarterly debt payments on the term loan through the Effective Period, as defined.

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

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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 cannot remove our general partner without its consent.
If our unitholders are dissatisfied with the performance of our general partner, they have limited ability to remove our general partner. Unitholders are currently unable to remove our general partner without its consent because our general partner and its affiliates own sufficient units to be able to prevent its removal. 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. As of December 31, 2016, our sponsor owned 32.5% of our common units.
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.
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.

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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, 2016, our sponsor owned 32.5% 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.

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Tax Risks to Common Unitholders
Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service (the "IRS") were to treat us as a corporation for federal income tax purposes or we were to become subject to material additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution to you could be substantially reduced.
The anticipated after-tax economic benefit of an investment in our common units depends largely on us being treated as a partnership for federal income tax purposes.
Despite the fact that we are organized as a limited partnership under Delaware law, as a publicly traded partnership we may be treated as a corporation for federal income tax purposes unless 90% or more of our gross income in each year consists of certain identified types of “qualifying income” as defined by Section 7704 of the Internal Revenue Code (the “Qualifying Income Exception”). In addition to qualifying income, like many other publicly traded partnerships, we also generate ancillary income that may not be considered qualifying income. We have historically satisfied, and believe we currently satisfy, the Qualifying Income Exception to be treated as a partnership for federal income tax purposes. Although we monitor our level of gross income that may not be considered qualifying income closely and attempt to manage our operations to ensure compliance with the Qualifying Income Exception, if weak demand and low prices for frac sand were to continue, the sale of which generates qualifying income, we may not be able to continue to meet the qualifying income level necessary to maintain our status as a publicly traded partnership treated as a partnership for federal income tax purposes. 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, determination by the IRS that such failure to meet the Qualifying Income Exception was inadvertent. However, we are unaware of examples of such relief being sought by a publicly traded partnership.
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 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. For example, from time to time, members of the U.S. Congress propose and consider substantive changes to the existing federal income tax laws that affect the tax treatment of publicly traded partnerships. Although there is no current legislative proposal, a prior legislative proposal would have eliminated the qualifying income exception to the treatment of all publicly traded partnerships as corporations 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.
Any modification to the federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for federal income tax purposes. 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 or whether the Final Regulations will be revised to materially change interpretations of the current law. 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.

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Our unitholders are required to pay taxes on their share of our income even if they do not receive any cash distributions from us.
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.
On October 26, 2015, our general partner's board of directors announced the temporary suspension of our quarterly distribution to common unitholders in order to conserve cash and preserve liquidity.
The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.
We will be considered to have terminated as a partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. Our termination would, among other things, result in the closing of our taxable year for all unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than the calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead, after our termination we would be treated as a new partnership for federal income tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred. The IRS has announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership may be permitted to provide only a single Schedule K-1 to unitholders for the two short tax periods included in the year in which the termination occurs.
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.
Tax-exempt entities and non-U.S. persons face unique tax issues from owning common units that may result in adverse tax consequences to them.
Investments in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (or “IRAs”), and non-U.S. persons 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, is unrelated business taxable income and is taxable to them. Distributions to non-U.S. persons are reduced by withholding taxes, and non-U.S. persons are required to file federal tax returns and pay tax on their shares of our taxable income. A unitholder that is a tax-exempt entity or a non-U.S. person should consult a tax advisor before investing in our 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 adjustment 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 adjustment 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 Schedule K-1 to each unitholder with respect to an audited and adjusted return. Although our general partner may elect to have our unitholders take such audit adjustment into account 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 cost of any IRS 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 by the IRS may materially and adversely impact the market for our common units and the price at which they trade. Our costs of any contest by the IRS 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 actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.
Because we cannot match transferors and transferees of common units and in order to maintain the uniformity of the economic and tax characteristics of our common units, we have adopted certain depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. These positions may result in an overstatement of deductions and losses and an understatement of income and gain to our unitholders. A successful IRS challenge to those positions 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 the sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to our unitholders’ 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 is no tax concept of loaning a partnership interest, a unitholder whose common units are the subject of a securities loan may be considered as having 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 loan to a short seller should modify any applicable brokerage account agreements to prohibit their brokers from borrowing their common units.

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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, 2016, 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
We are managed and operated by the board of directors and executive officers of our general partner, which leases office space for our principal executive offices in Houston, Texas. As of December 31, 2016, we operated three production facilities located in Wyeville, Augusta and near Blair, all in Wisconsin, of which we own all associated land. In addition, we own or operate 11 terminal locations, lease or own 4,200 railcars used to transport our sand from origin to the terminal and we lease 300 containers used to transport our sand from the terminal to the well site. Substantially all of our owned assets are pledged as security under our Revolving Credit Agreement and senior secured term loan 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, 2016, the Wyeville facility produced and delivered 1,937,793 tons of frac sand. As of December 31, 2016, the total cost of our plant and equipment was $65.9 million. The plant is in good physical condition and includes modern equipment powered by natural gas and electricity.
We operate two dryer facilities at the Wyeville facility with a combined nameplate input capacity, based on manufacturer specifications, of 250 tons per hour. Unless processing operations are suspended to conduct maintenance, our dryer facilities are run on a 24-hour basis. Our estimate of annual expected processing capacity assumes a 15% loss factor due to waste and an uptime efficiency of 85% of nameplate capacity, which allows approximately 55 days for downtime and maintenance.
All of the product from the Wyeville facility is shipped by rail from approximately 32,000 feet of track that connects our facility to a Union Pacific Railroad mainline. These rail spurs and the capacity of the associated product storage silos allow us to accommodate a large number of railcars, including unit trains.
The following table summarizes certain of the key characteristics of our Wyeville facility that we believe allow us to efficiently provide our customers with high quality frac sand efficiently at competitive prices.
Facility Characteristics
 
Description
Site Geography
 
Situated on 971 contiguous acres, with on-site processing and rail loading facilities.
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.

40


Augusta Facility
We completed construction of the Augusta facility in June 2012 and expanded the facility in 2014. The Augusta facility has an annual processing capacity of approximately 2,860,000 tons of frac sand per year. The Augusta facility was idled in October 2015 and resumed production in September 2016. During the year ended December 31, 2016, the Augusta facility produced and delivered 373,115 tons of frac sand. As of December 31, 2016, the total cost of the Augusta facility and equipment was $106.9 million. The plant is in good physical condition and includes modern equipment powered by natural gas and electricity.
We operate three dryer facilities at the Augusta facility with a combined nameplate input capacity, based on manufacturer specifications, of 400 tons per hour. Unless processing operations are suspended to conduct maintenance, Augusta’s dryer facilities are run on a 24-hour basis. Our estimate of annual expected processing capacity assumes a 15% loss of capacity due to waste and an uptime efficiency of 85% of nameplate capacity, which allows approximately 55 days for downtime and maintenance.
All of the product from the Augusta facility is shipped by rail from approximately 28,800 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.
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, 2016, the Blair facility produced and delivered 1,482,355 tons of frac sand. As of December 31, 2016, the total cost of Blair facility and equipment was $102.2 million. The plant is in good physical condition and includes modern equipment powered by natural gas and electricity.
We operate two dryer facilities at the Blair facility with a combined nameplate input capacity, based on manufacturer specifications, of 400 tons per hour. Unless processing operations are suspended to conduct maintenance, Blair's dryer facilities are run on a 24-hour basis. Our estimate of annual expected processing capacity assumes a 15% loss of capacity due to waste and an uptime efficiency of 85% of nameplate capacity, which allows approximately 55 days for downtime and maintenance.
All of the product from the Blair facility is shipped by rail from approximately 43,000 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.
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.

41


Terminals
As of December 31, 2016, we own or operate 11 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 (a)
 
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
 
 
Smithfield, PA
 
Rail/Silo
 
Southwest Pennsylvania Railroad
 
þ
 
þ
Wellsboro, PA
 
Rail/Silo
 
Wellsboro & Corning Railroad
 
þ
 
þ
(a)
As a result of market conditions we elected to temporarily idle certain of our terminals.
During the year ended December 31, 2016, the Partnership sold two of the previously idled transload facilities and the leases for two of the idled transload facilities terminated. As of December 31, 2016, we leased or owned 4,200 railcars used to transport our sand from origin to the terminal and we lease 300 containers used to transport our sand from the terminal to the well site.
Sand Reserves
We own and operate the Wyeville, Augusta and Blair facilities, which as of December 31, 2016, contained 76.4 million tons, 40.9 million tons, and 117.7 million tons, respectively, of proven recoverable reserves of frac sand.
“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 Wyeville, Augusta and Blair 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, 2016, 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.
Our reserves are a mineral resource created over millions of years. Approximately 500 million years ago, the quartz rich Cambrian sheet sands were deposited in the upper Midwest region of the United States. During the Pleistocene era, which occurred approximately two million years ago, erosion caused by the melting of glaciers cut channels into the Mount Simon sandstone formation, forming rivers. Loose grains of sand resulting from this same erosion settled in these river beds where they were washed by the consistent current of the river. The washing action of the river removed debris, known as fines, from the sand, rounded the sand grains and helped it to remain unconsolidated.
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.

42


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.
Mineral Rights
We acquired the Wyeville, Augusta and Blair 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.
Summary of Reserves
The following table provides a summary of our Wyeville, Augusta and Blair facilities, and our sponsor's Whitehall facility, as of December 31, 2016:
Mine/Plant Location         
 
Owned/Leased      
 
Area (in acres)    
 
Proven Reserves (in thousands of tons)  
 
Primary End Markets Served    
Wyeville, WI
 
Owned
 
971
 
76,439

 
Oil and gas proppants
Augusta, WI (a)
 
Owned
 
1,187
 
40,927

 
Oil and gas proppants
Blair, WI
 
Owned
 
1,285
 
117,675

 
Oil and gas proppants
Whitehall, WI (b)
 
Owned
 
1,447
 
80,700

 
Oil and gas proppants
(a)
Our sponsor owns 2% of Hi-Crush Augusta LLC, the entity that owns the Augusta facility.
(b)
Our sponsor owns 100% of the facility.

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.


43


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, 2015
 
$
40.00

 
$
28.23

June 30, 2015
 
$
40.40

 
$
27.53

September 30, 2015
 
$
31.00

 
$
7.44

December 31, 2015
 
$
9.51

 
$
5.05

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

Cash Distributions To Limited Partner Unitholders
For the Quarter Ended
 
Record Date
 
Payment Date
 
Amount per
Limited Partner  
Unit
March 31, 2015
 
May 1, 2015
 
May 15, 2015
 
$
0.6750

June 30, 2015
 
August 5, 2015
 
August 14, 2015
 
$
0.4750

On October 26, 2015, we announced the Board of Directors' decision to temporarily suspend the distribution payment to common unitholders. No quarterly distributions were declared for the third quarter of 2015 or thereafter, as the Partnership continued its distribution suspension to conserve cash. It is currently uncertain when market conditions will improve to a level at which time the General Partner's board of directors would consider it appropriate to reinstate the distribution.
As of December 31, 2016, there were 63,668,244 common units outstanding held by approximately 21,479 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. As of December 31, 2016, our sponsor owned 20,693,643 common units.
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 restrictions on distributions under our Revolving Credit Agreement and senior secured term loan facility, which contain financial tests and covenants that we must satisfy. Our Revolving Credit Agreement allows distributions to unitholders up to 50% of quarterly distributable cash flow after quarterly debt payments on the term loan during the Effective Period, as defined. Should we be unable to satisfy these restrictions 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.

44


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 shown for our unitholders and our sponsor (as the holder of our incentive distribution rights) for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below assume our sponsor has not transferred its incentive distribution rights and there are no arrearages on common units.

45


 
 
 
 
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 Part III, 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, 2016.
Recent Sales of Unregistered Securities
On August 31, 2016, in connection with our acquisition of all of the outstanding membership interests in Hi-Crush Blair, we issued, 7,053,292 common units to our sponsor.  The common units were issued pursuant to an exemption from registration under Section 4(a)(2) of the Securities Act of 1933, as amended.
Purchase of Equity Securities by the Issuer and Affiliated Purchasers
None.
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 plan as of December 31, 2016.


46


ITEM 6. SELECTED FINANCIAL DATA
The Partnership's historical financial data has been recast to include Hi-Crush Augusta LLC for the periods from August 16, 2012 through December 31, 2014. The Predecessor periods include Hi-Crush Augusta LLC as a subsidiary of Hi-Crush Proppants LLC and were thus not subject to recast. In addition, the Partnership's historical financial data has been recast to include Hi-Crush Blair LLC for the years ended December 31, 2016, 2015 and 2014.
 
Year Ended December 31,
 
Period from August 16 Through December 31, 2012
 
Period from January 1 Through August 15, 2012
(in thousands, except tons, per ton and per unit amounts)
2016
 
2015
 
2014
 
2013
 
 
Successor
 
Successor
 
Successor
 
Successor
 
Successor
 
Predecessor
Statement of Operations Data:
 
 
 
 
 
 
 
 
 
 
 
Revenues
$
204,430

 
$
339,640

 
$
386,547

 
$
178,970

 
$
31,770

 
$
46,776

Production costs
45,474

 
48,371

 
58,452

 
41,999

 
8,944

 
12,247

Other cost of sales
143,719

 
199,801

 
156,904

 
46,688

 

 

Depreciation and depletion
15,437

 
13,199

 
10,628

 
7,197

 
1,109

 
1,089

Cost of goods sold
204,630

 
261,371

 
225,984

 
95,884

 
10,053

 
13,336

Gross profit (loss)
(200
)
 
78,269

 
160,563

 
83,086

 
21,717

 
33,440

Operating costs and expenses:
 
 
 
 
 
 
 
 
 
 
 
General and administrative
33,198

 
24,890

 
26,451

 
19,096

 
3,757

 
4,631

Impairments and other expenses
34,025

 
25,659

 

 
47

 
121

 
539

Accretion expense
369

 
336

 
246

 
228

 
102

 
16

Other operating income

 
(12,310
)
 

 

 

 

Income (loss) from operations
(67,792
)
 
39,694

 
133,866

 
63,715

 
17,737

 
28,254

Other income (expense):
 
 
 
 
 
 
 
 
 
 
 
Other income

 

 

 

 

 
6

Interest expense
(13,341
)
 
(13,903
)
 
(9,946
)
 
(3,671
)
 
(320
)
 
(3,240
)
Net income (loss)
(81,133
)
 
25,791

 
123,920

 
60,044

 
17,417

 
25,020

(Income) loss attributable to non-controlling interest
99

 
(145
)
 
(955
)
 
(274
)
 
23

 

Net income (loss) attributable to Hi-Crush Partners LP
$
(81,034
)
 
$
25,646

 
$
122,965

 
$
59,770

 
$
17,440

 
$
25,020

Earnings per limited partner unit:
 
 
 
 
 
 
 
 
 
 
 
Limited partner units - basic
$
(1.64
)
 
$
0.73

 
$
3.09

 
$
2.08

 
$
0.68

 
 
Limited partner units - diluted
$
(1.64
)
 
$
0.73

 
$
3.00

 
$
2.08

 
$
0.68

 
 
Distributions per limited partner unit
$

 
$
1.1500

 
$
2.4000

 
$
1.9500

 
$
0.7125

 
 
Statement of Cash Flow Data:
 
 
 
 
 
 
 
 
 
 
 
Net cash provided by (used in):
 
 
 
 
 
 
 
 
 
 
 
Operating activities
$
(26,644
)
 
$
83,649

 
$
104,265

 
$
64,323

 
$
14,498

 
$
16,660

Investing activities
(126,420
)
 
(120,667
)
 
(306,431
)
 
(105,585
)
 
(8,218
)
 
(80,045
)
Financing activities
146,324

 
43,263

 
186,367

 
51,372

 
2,234

 
61,048

Other Financial Data:
 
 
 
 
 
 
 
 
 
 
 
Adjusted EBITDA (a)
$
(16,921
)
 
$
79,376

 
$
147,910

 
$
73,534

 
$
18,846

 
$
29,349

Capital expenditures (b)
42,591

 
121,358

 
82,181

 
10,630

 
8,218

 
80,075

Operating Data:
 
 
 
 
 
 
 
 
 
 
 
Total tons sold
4,253,746

 
5,003,702

 
4,584,811

 
2,520,119

 
481,208

 
726,213

Average realized price (per ton sold)
$
47.65

 
$
62.05

 
$
70.46

 
$
65.64

 
$
66.02

 
$
64.41

Sand produced and delivered (in tons)
3,793,263

 
3,506,193

 
3,704,630

 
2,241,199

 
481,208

 
726,213

Contribution margin per ton sold
$
3.58

 
$
18.28

 
$
37.34

 
$
35.82

 
$
47.43

 
$
47.55

Balance Sheet Data (at period end)
 
 
 
 
 
 
 
 
 
 
 
Cash
$
4,314

 
$
11,054

 
$
4,809

 
$
20,608

 
$
10,498

 
$
8,717

Total assets
529,310

 
534,208

 
481,829

 
354,361

 
189,397

 
175,828

Long-term debt
193,458

 
246,783

 
198,364

 
138,250

 

 
111,402

Total liabilities
236,428

 
394,519

 
303,311

 
171,007

 
94,270

 
140,747

Equity
292,882

 
139,689

 
178,518

 
183,354

 
95,127

 
35,081


47


(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.
Non-GAAP Financial Measures
EBITDA and Adjusted EBITDA
We define EBITDA as net income plus depreciation, depletion and amortization and interest and debt expense, net of interest income. We define Adjusted EBITDA as EBITDA, adjusted for any non-cash impairments of goodwill and long-lived assets. 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.
Distributable Cash Flow
We define distributable cash flow as Adjusted EBITDA less cash paid for interest expense, income attributable to non-controlling interests 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.


48


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,
 
Period from August 16 Through December 31, 2012
 
Period from January 1 Through August 15, 2012
 
2016
 
2015
 
2014
 
2013
 
 
(in thousands)
Successor
 
Successor
 
Successor
 
Successor
 
Successor
 
Predecessor
Net income (loss)
$
(81,133
)
 
$
25,791

 
$
123,920

 
$
60,044

 
$
17,417

 
$
25,020

Depreciation and depletion expense
15,444

 
12,270

 
8,858

 
6,132

 
1,109

 
1,089

Amortization expense
1,682

 
2,620

 
5,186

 
3,687

 

 

Interest expense
13,341

 
13,903

 
9,946

 
3,671

 
320

 
3,240

EBITDA
(50,666
)
 
54,584

 
147,910

 
73,534

 
18,846

 
29,349

Non-cash impairments of goodwill and long-lived assets
33,745

 
24,792

 

 

 

 

Adjusted EBITDA
(16,921
)
 
79,376

 
147,910

 
73,534

 
18,846

 
$
29,349

Less: Cash interest paid
(11,475
)
 
(11,610
)
 
(8,682
)
 
(3,123
)
 
(193
)
 
 
Less: (Income) loss attributable to non-controlling interest
99

 
(145
)
 
(955
)
 
(274
)
 
23

 
 
Less: Maintenance and replacement capital expenditures, including accrual for reserve replacement (a)
(5,121
)
 
(4,733
)
 
(5,001
)
 
(3,026
)
 
(649
)
 
 
Add: Accretion of asset retirement obligations
369

 
336

 
246

 
228

 
102

 
 
Add: Unit-based compensation
2,620

 
2,983

 
1,470

 

 

 
 
Distributable cash flow
(30,429
)
 
66,207

 
134,988

 
67,339

 
18,129

 
 
Adjusted for: Distributable cash flow attributable to Hi-Crush Augusta LLC, net of intercompany eliminations, prior to the Augusta Contribution (b)

 

 
(7,199
)
 
696

 
832

 
 
Adjusted for: Distributable cash flow attributable to Hi-Crush Blair LLC, prior to the Blair Contribution (c)
(747
)
 
2,619

 
105

 

 

 
 
Distributable cash flow attributable to Hi-Crush Partners LP
(31,176
)
 
68,826

 
127,894

 
68,035

 
18,961

 
 
Less: Distributable cash flow attributable to holders of incentive distribution rights

 
(1,311
)
 
(18,401
)
 

 

 
 
Distributable cash flow attributable to limited partner unitholders
$
(31,176
)
 
$
67,515

 
$
109,493

 
$
68,035

 
$
18,961

 
 
(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 during the period. 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 for the periods from August 16, 2012 through December 31, 2014. 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 Augusta Contribution.
(c)
The Partnership's historical financial information has been recast to consolidate Blair for the years ended December 31, 2016, 2015 and 2014. For purposes of calculating distributable cash flow attributable to Hi-Crush Partners LP, the Partnership excludes the incremental amount of recast distributable cash flow (loss) during the periods prior to the Blair Contribution.

49


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 an integrated producer, transporter, marketer and distributor of high-quality monocrystalline sand, a specialized mineral that is used as a proppant to enhance the recovery rates of hydrocarbons from oil and natural gas wells. Our reserves, which are located in Wisconsin, consist of "Northern White" sand, a resource that exists predominately in Wisconsin and limited portions of the upper Midwest region of the United States. The Partnership owns and operates a portfolio of sand facilities with on-site wet and dry plant assets, including direct access to major U.S. railroads for distribution to in-basin terminals. We own and operate a network of strategically located terminals and an integrated distribution system throughout North America, including our PropStreamTM integrated logistics solution, which delivers proppant into the blender at the well site.
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"), for total cash consideration of $261,750 and 3,750,000 newly issued convertible Class B units in the Partnership (the “Augusta Contribution”). Subsequently on August 15, 2014, our sponsor, as the sole owner of our Class B units, elected to convert all of the 3,750,000 Class B units into common units on a one-for-one basis.
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 shales.
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 earnout consideration (the "Blair Contribution"). The Partnership completed the acquisition of the Blair facility on August 31, 2016.
Our Assets and Operations
We own and operate a 971-acre facility with approximately 32,000 feet of integrated rail infrastructure, located in Wyeville, Wisconsin (the "Wyeville facility") and, as of December 31, 2016, contained 76.4 million tons of proven recoverable reserves of frac sand. 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.
We also own a 98.0% interest in the 1,187-acre Augusta facility with approximately 28,800 feet of integrated rail infrastructure and, as of December 31, 2016, contained 40.9 million tons of proven recoverable reserves of frac sand. We completed construction of the Augusta facility in June 2012. 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 previously idled as a result of market conditions.
We also own the 1,285-acre Blair facility, with approximately 43,000 feet of integrated rail infrastructure and, as of December 31, 2016, contained 117.7 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.
During the third quarter of 2014, our sponsor completed construction of the 1,447-acre facility with approximately 30,000 feet of integrated rail infrastructure, located near Independence, Wisconsin and Whitehall, Wisconsin (the "Whitehall facility"). As of December 31, 2016, this facility contained 80.7 million tons of proven recoverable reserves of frac sand and 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 is expected to resume operations in late March or early April 2017.

50


According to John T. Boyd Company ("John T. Boyd"), our proven reserves at the Wyeville, Augusta and Blair facilities consist of Northern White sand exceeding American Petroleum Institute (“API”) minimum specifications. Analysis of sand at our facilities by independent third-party testing companies indicates that they demonstrate characteristics exceeding of API minimum 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 31 years, assuming production at the rated capacity of 7,570,000 tons of frac sand per year.
As of December 31, 2016, we own or operate 11 terminal locations, of which three are temporarily idled and six are capable of accommodating unit trains. Our terminals include approximately 74,000 tons of rail storage capacity and approximately 120,000 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, 2016, we leased or owned 4,200 railcars used to transport our sand from origin to destination and managed a fleet of approximately 1,358 additional railcars dedicated to our facilities by our customers or the Class I railroads.
In September 2016, the Partnership entered into an agreement to form Proppant Express Investments, LLC ("PropX"), which was established to develop critical last-mile logistics equipment for the proppant industry. In October 2016, the Partnership announced the successful pilot test of its PropStream integrated logistics solution, which involves loading frac sand at in-basin terminals into PropX containers before being transported by truck to the well site. At the well site, the proprietary conveyor system (“PropBeast™”) significantly reduces noise and dust emissions due to its fully enclosed environment. As of December 31, 2016, we owned 6 PropBeast conveyors and leased 300 containers from PropX. 
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 2017 and 2021. Each contract defines the minimum volume of frac sand that the customer is required to purchase monthly and annually, the volume that we are required to make available, the technical specifications of the product and the price per ton. During 2016, we continued to provide temporary price discounts and/or waivers of minimum volume purchase requirements to contract customers in response to the market driven decline in proppant demand. 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 well site. We generate service revenues through performance of transportation services including railcar storage fees, transload services, silo storage and other miscellaneous services performed on behalf of our customers.
Due to sustained freezing temperatures in our area 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 those facilities are operational. This excess sand is placed in stockpiles that feed the dry plant and fill customer orders throughout the year.
Costs of Conducting Our Business
The principal expenses involved in production of raw frac sand are excavation 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.

51


We pay royalties to third parties at our 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 September 2016, with another payment scheduled for August 2017. 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, delivered at our on-site rail facilities and paid for by our customers.
The principal expenses involved in distribution of raw sand are the cost of purchased sand, freight charges, fuel surcharges, railcar lease expense, terminal switch fees, demurrage costs, storage fees, transload fees, labor and facility rent. The principal expenses involved in delivering sand to the well site are costs associated with trucking, container rent, labor and other operating expenses associated with handling the product from the terminal to the well site.
We purchase sand from our sponsor's Whitehall facility, through a long-term supply agreement with a third party at a specified price per ton and also through the spot market. We incur transportation costs including trucking, rail freight charges and fuel surcharges when transporting our sand from its origin to destination. We utilize multiple railroads to transport our sand and transportation costs are typically negotiated through long-term working relationships.
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 are 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, 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.
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 and debt expense, net of interest income. We define Adjusted EBITDA as EBITDA, adjusted for any non-cash impairments of goodwill and long-lived assets. We define distributable cash flow as Adjusted EBITDA less cash paid for interest expense, income attributable to non-controlling interests 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.

52


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:
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 2016, we began providing 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. We continue to engage in discussions and may continue to deliver sand at prices or at volumes below those provided for in our existing contracts. Through December 31, 2016 these circumstances have negatively affected our revenues, net income and cash generated from operations.
Our Augusta production facility was temporarily idled from October 2015 through August 2016. On October 9, 2015, we announced a reduction in force to our employees in connection with the temporary idling of our Augusta production facility, which has a higher cost structure than our lowest cost production facility. During September 2016, the Partnership resumed production at its Augusta facility. The temporary idling of Augusta resulted in a decrease in volumes produced and delivered during 2016 as compared to 2015.
We completed construction of our Blair facility. 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.
Our sponsor's Whitehall facility did not commence operations until September 2014. Our first purchase of frac sand from the Whitehall facility occurred in September 2014. As a result of market conditions, the Whitehall facility was temporarily idled during the second quarter of 2016 and the Partnership only purchased $8,086 of sand from the Whitehall facility during 2016.
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 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 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 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 source sand from our sponsor 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.

53


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.
Our outstanding balance under the 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 senior secured revolving credit agreement (the "Revolving Credit Agreement"). As a result, our interest expense decreased during 2016 as compared to 2015.
During the fourth quarter of 2016, we launched PropStream, our integrated logistics solution, which delivers proppant into the blender at the well site. We incurred $1,125 in losses associated with the lower asset utilization rates and up front start-up costs during the initial roll out of the solution.
Market Conditions
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. As a result, the number of rigs drilling for oil and gas fell dramatically from the high levels achieved during third quarter of 2014; however, since the second quarter of 2016, the rig count has improved as oil and gas prices have somewhat stabilized. Specifically, the reported Baker Hughes oil rig count in North America fell from a high of 1,589 rigs in August 2014 to a low of 316 rigs in May 2016 and has recovered to 525 rigs as of December 31, 2016, which is relatively flat with the rig count as of December 31, 2015. As of February 10, 2017, the rig count is at 591 rigs. Due to the uncertainty experienced over the past two years regarding the timing and extent of a recovery, exploration and production companies sharply reduced their drilling and completion activities in an effort to control costs. As a result, our customers faced uncertainty related to overall activity levels, and well completion activity was significantly below levels experienced in 2014 and 2015. The combination of these, and other factors reduced proppant demand and pricing during 2016, and significantly from the levels experienced during 2014. Proppant demand did not decline as significantly as the rig count and well completion activity might imply, though, due to the continuing trend of longer laterals and increasing use of sand per lateral foot in well completions. Given the marginal improvement in exploration and production activity during the fourth quarter of 2016 and the energy industry's outlook for 2017 activity levels, we expect the recent years' downward trend in well completion activity to reverse 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.
Spot market prices for frac sand have declined dramatically from the levels experienced in 2014, as sand producers, particularly those with excess inventories, substantially discounted sand pricing in order to sell product in a lower demand environment. Pricing continued to decline throughout 2015 and continued in 2016, but began to stabilize in the third quarter of 2016 and increase in the fourth quarter of 2016, although remaining near historically low levels. While the outlook for pricing of raw frac sand in 2017 is uncertain, 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 in the first quarter of 2017 and is likely to be more favorable in 2017.
In 2015, as a result of the market dynamics existing during the year and continuing in 2016, we began providing 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. We continue to engage in discussions and may continue to deliver sand at prices or at volumes below those provided for in our existing contracts. We expect that these circumstances may continue to negatively affect our revenues, net income and cash generated from operations in 2017.
Over the past two years, we have taken several steps to ensure we continue to deliver low-cost solutions to our customers. We eliminated the volumes of sand purchased from third parties, and worked to ensure that volumes were sourced at our lowest cost facilities, combining our lowest production cost with the lowest origin to destination freight rates where possible. In 2015, we temporarily idled production at our Augusta facility, idled several transload facilities and closed an administrative office, reducing headcount and eliminating costs. In 2016, we further reduced headcount and our sponsor temporarily idled its Whitehall facility. We strategically managed the size of our railcar fleet by eliminating the use of system cars to reduce cost and returning cars at the end of their lease term. As of December 31, 2016, we have 605 railcars in long-term storage and will continue to incur storage expense related to these cars until they are removed from storage. Our proactive fleet management resulted in minimizing paid storage for idled railcars compared to our competitors.

54


As market conditions have improved since the second quarter of 2016, we have taken additional steps to ensure we are positioned to serve our customers with their increasing levels of well completions activity.  We completed the construction of additional in-basin storage facilities and have established relationships with additional third-party operated terminals.  In September 2016, we resumed production at our Augusta facility and our sponsor is in the process of performing the required maintenance at its Whitehall facility to enable resuming production when market conditions warrant.  We have continued to provide market-based pricing to our customers and are engaged in discussions to increase pricing and volumes as their activity levels increase. Additionally in October 2016, the Partnership announced the launch of its new PropStream integrated logistics solution, which delivers proppant into the blender at the well site.
The following table presents sales, volume and pricing comparisons for the fourth quarter of 2016, as compared to the third quarter of 2016:
 
Three Months Ended
 
 
 
 
 
December 31,
 
September 30,
 
 
 
Percentage
 
2016
 
2016
 
Change
 
Change
Revenues generated from the sale of frac sand (in thousands)
$
66,037

 
$
46,546

 
$
19,491

 
42
%
Tons sold
1,358,511

 
1,082,974

 
275,537

 
25
%
Percentage of volumes sold in-basin
57
%
 
47
%
 
10
%
 
21
%
Average price per ton sold
$
49

 
$
43

 
$
6

 
14
%
Tons sold during the fourth quarter were 25% higher than the third quarter of 2016 as market demand increased in line with rig count increases and well completion activity. The increased volumes coupled with an increased percentage of volumes being sold in-basin led to the increase in frac sand revenues as compared to the prior quarter.
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, 2016, 2015 and 2014.
 
Year Ended December 31,
 
2016
 
2015
 
2014
Revenues
$
204,430

 
$
339,640

 
$
386,547

Costs of goods sold
 
 
 
 
 
Production costs
45,474

 
48,371

 
58,452

Other cost of sales
143,719

 
199,801

 
156,904

Depreciation, depletion and amortization
15,437

 
13,199

 
10,628

Gross profit (loss)
(200
)
 
78,269

 
160,563

Operating costs and expenses
67,592

 
38,575

 
26,697

Income (loss) from operations
(67,792
)
 
39,694

 
133,866

Other income (expense)
 
 
 
 
 
Interest expense
(13,341
)
 
(13,903
)
 
(9,946
)
Net income (loss)
(81,133
)
 
25,791

 
123,920

(Income) loss attributable to non-controlling interest
99

 
(145
)
 
(955
)
Net income (loss) attributable to Hi-Crush Partners LP
$
(81,034
)
 
$
25,646

 
$
122,965


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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 in-basin
54
%
 
51
%
 
3
%
 
6
 %
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 FOB plant and in-basin volumes (54% and 51% of tons were sold in-basin for the years ended December 31, 2016 and 2015, respectively). 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 revenue related to transload, terminaling, silo leases, 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 $45,474 and $48,371 for the years ended December 31, 2016 and 2015, respectively, reflecting a decreased percentage of volumes being produced at our higher cost facilities, offset by an increase in tons produced and delivered.
The principal components of production costs involved in operating our business are excavation costs, plant operating costs and royalties. Such costs, with the exception of royalties, are capitalized as a component of inventory and are reflected in costs of goods sold when inventory is sold. Royalties are charged to expense in the period in which they are incurred. The following table provides a comparison of the drivers impacting the level of production costs for the years ended December 31, 2016 and 2015.
 
Year Ended December 31,
 
2016
 
2015
Excavation costs
$
16,292

 
$
13,240

Plant operating costs
23,447

 
24,820

Royalties
5,735

 
10,311

   Total production costs
$
45,474

 
$
48,371


56


Costs of goods sold – Other cost of sales
The other principal costs of goods sold are the cost of purchased sand, freight charges, fuel surcharges, railcar lease expense, terminal switch fees, demurrage costs, storage fees, transload fees, labor and facility rent. The cost of purchased sand and transportation related charges are capitalized as a component of inventory and are reflected in cost of goods sold when inventory is sold. Other cost components, including costs associated with storage in-basin and costs related to terminal operations, such as labor and rent, are charged to costs of goods sold in the period in which they are incurred.
 
Year Ended December 31,
 
2016
 
2015
Purchases of sand
$
8,086

 
$
36,160

Transportation costs
120,811

 
143,006

Other cost of sales
14,822

 
20,635

   Total other cost of sales
$
143,719

 
$
199,801

We procure sand from our facilities and our sponsor's Whitehall facility, and in 2015, through a long-term supply agreement with a third party at a specified price per ton. For the years ended December 31, 2016 and 2015, we purchased $8,086 and $36,160 of sand, respectively. The decrease was due to a lower average purchase price paid in 2016 as compared to 2015 and lower volumes purchased in 2016 as our sponsor temporarily idled its Whitehall facility during the second quarter of 2016.
We incur transportation costs including freight charges, fuel surcharges and railcar lease costs when transporting our sand from its origin to destination. For the years ended December 31, 2016 and 2015, we incurred $120,811 and $143,006 of transportation costs, respectively. Other costs of sales was $14,822 and $20,635 during the years ended December 31, 2016 and 2015, respectively, and was primarily comprised of demurrage, storage and transload fees and on-site labor. The decrease in transportation and other costs of sales was driven by decreased in-basin sales volumes, 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. The year ended December 31, 2015 was negatively impacted by repair costs of silos at our Smithfield terminal and increased rail diversion and storage costs primarily as a result of railcar moves to the Partnership's production facilities and long-term third party storage facilities.
Costs of goods sold – Depreciation, depletion and amortization of intangible assets
For the years ended December 31, 2016 and 2015, we incurred $15,437 and $13,199, 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 $200 for the year ended December 31, 2016, compared to gross profit of $78,269 for the year ended December 31, 2015. Gross profit (loss) percentage declined to (0.1)% for the year ended December 31, 2016 from 23.0% 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.
Operating Costs and Expenses
For the years ended December 31, 2016 and 2015, we incurred total operating costs and expenses of $67,592 and $38,575, respectively. For the years ended December 31, 2016 and 2015, we incurred general and administrative expenses of $33,198 and $24,890, 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 $13,341 and $13,903 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.

57


Net Income (Loss) Attributable to Hi-Crush Partners LP
Net loss attributable to Hi-Crush Partners LP was $81,034 for the year ended December 31, 2016, compared to net income attributable to Hi-Crush Partners LP of $25,646 for the year ended December 31, 2015.
Year Ended December 31, 2015 Compared to Year Ended December 31, 2014
Revenues
The following table presents sales, volume and pricing comparisons for the year ended December 31, 2015, as compared to the year ended December 31, 2014:
 
Year Ended December 31,
 
 
 
Percentage
 
2015
 
2014
 
Change
 
Change
Revenues generated from the sale of frac sand (in thousands)
$
310,466

 
$
323,043

 
$
(12,577
)
 
(4
)%
Tons sold
5,003,702

 
4,584,811

 
418,891

 
9
 %
Percentage of volumes sold in-basin
51
%
 
33
%
 
18
%
 
55
 %
Average price per ton sold
$
62

 
$
70

 
$
(8
)
 
(11
)%
Revenues generated from the sale of frac sand was $310,466 and $323,043 for the years ended December 31, 2015 and 2014, respectively, during which we sold 5,003,702 and 4,584,811 tons of frac sand, respectively. Average sales price per ton was $62 and $70 for the years ended December 31, 2015 and 2014, respectively. The average sales price between the two periods differs due to the mix in pricing of FOB plant and in-basin volumes (51% and 33% of tons were sold in-basin for the years ended December 31, 2015 and 2014, respectively), offset by changes in industry sales price trends. With the decline in oil and gas prices and resulting decline in drilling activity, we began discounting pricing for contract customers during 2015. Generally, sales prices per ton were rising throughout 2014, and declining throughout 2015. Price per ton exiting 2015 was significantly lower than 2014. Average sales price per ton was also somewhat impacted by the mix of product mesh sizes.
Other revenue related to transload, terminaling, silo leases, contract make-wholes and other services was $29,174 and $63,504 for the years ended December 31, 2015 and 2014, respectively. The level of transloading and logistics services provided at our terminals was increasing during 2014, and decreasing significantly during the corresponding period of 2015, both trends being in-line with industry demand for sand and our sales volumes. In addition, other revenue in 2015 includes $10,190 of make-whole payments related to the contract settlement payment.
Costs of goods sold – Production costs
We incurred production costs of $48,371 and $58,452 for the years ended December 31, 2015 and 2014, respectively. The overall decrease in production costs was attributable to lower excavation costs paid to our third party excavator, improved operating efficiencies, which resulted in reduced volumes of rejected material, and a focus on sourcing our sand from our lowest cost facility and lower tonnage produced and delivered from our production facilities during the year ended December 31, 2015 as compared to the year ended December 31, 2014.
The principal components of production costs involved in operating our business are excavation costs, plant operating costs and royalties. Such costs, with the exception of royalties, are capitalized as a component of inventory and are reflected in costs of goods sold when inventory is sold. Royalties are charged to expense in the period in which they are incurred. The following table provides a comparison of the drivers impacting the level of production costs for the years ended December 31, 2015 and 2014.
 
Year Ended December 31,
 
2015