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EX-31.2 - EXHIBIT 31.2 - Hi-Crush Inc.exhibit312-fy14.htm
EX-32.3 - EXHIBIT 32.3 - Hi-Crush Inc.exhibit323-fy14.htm
EX-31.1 - EXHIBIT 31.1 - Hi-Crush Inc.exhibit311-fy14.htm
EX-32.1 - EXHIBIT 32.1 - Hi-Crush Inc.exhibit321-fy14.htm
EX-95.1 - EXHIBIT 95.1 - Hi-Crush Inc.exhibit951-fy14.htm
EX-32.2 - EXHIBIT 32.2 - Hi-Crush Inc.exhibit322-fy14.htm
EX-31.3 - EXHIBIT 31.3 - Hi-Crush Inc.exhibit313-fy14.htm
EX-23.1 - EXHIBIT 23.1 - Hi-Crush Inc.exhibit231-pwcconsent.htm
EX-23.2 - EXHIBIT 23.2 - Hi-Crush Inc.exhibit232-jtboydconsent.htm
EX-21.1 - EXHIBIT 21.1 - Hi-Crush Inc.exhibit211-listingofsubsid.htm
EX-23.3 - EXHIBIT 23.3 - Hi-Crush Inc.exhibit233-freedoniagroupc.htm
EXCEL - IDEA: XBRL DOCUMENT - Hi-Crush Inc.Financial_Report.xls
EX-10.25 - EXHIBIT 10.25 - Hi-Crush Inc.exhibit1025-halame.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, 2014
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 1550, Houston, Texas
77056
(Address of Principal Executive Offices)
(Zip Code)
Registrant’s telephone number, including area code (713) 960-4777
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    þ
Accelerated filer    ¨
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, 2014, 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 $1,200,982,167 based on the closing price of $65.56 per common unit on that date.
The registrant had 23,318,419 common units and 13,640,351 subordinated units outstanding on February 27, 2015.



INDEX TO FORM 10-K
PART I
Item 1. Business
Item 1A. Risk Factors
Item 2. Properties
PART II
PART III
PART IV




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,” “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 amount of frac sand we are able to excavate and process, which could be adversely affected by, among other things, operating difficulties and unusual or unfavorable geologic conditions;
the volume of frac sand we are able to buy and sell;
the price at which we are able to buy and sell frac sand;
changes in the price and availability of natural gas, diesel fuel or electricity;
changes in prevailing economic conditions, including the extent of changes in natural gas, crude oil and other commodity prices;
unanticipated ground, grade or water conditions;
inclement or hazardous weather conditions, including flooding, and the physical impacts of climate change;
environmental hazards;
difficulties in obtaining or renewing environmental permits;
industrial accidents;
changes in laws and regulations (or the interpretation thereof) related to the mining and hydraulic fracturing industries, silica dust exposure or the environment;
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;
facility shutdowns in response to environmental regulatory actions;
inability to obtain necessary production equipment or replacement parts;
reduction in the amount of water available for processing;
technical difficulties or failures;
labor disputes and disputes with our excavation contractor;
late delivery of supplies;
difficulty collecting receivables;
inability of our customers to take delivery;
changes in the price and availability of transportation;
fires, explosions or other accidents;
cave-ins, pit wall failures or rock falls;
our ability to borrow funds and access capital markets;
changes in the political environment of the drilling basins in which we and our customers operate; and
changes in railroad infrastructure, price, capacity and availability, including the potential for rail line washouts.
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.


1


PART I


2


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.
General
Hi-Crush Partners LP (together with its subsidiaries, the “Partnership”) is a Delaware limited partnership formed on May 8, 2012 to acquire selected sand reserves and related processing and transportation facilities of Hi-Crush Proppants LLC. In connection with its formation, the Partnership issued a non-economic general partner interest to Hi-Crush GP LLC, our general partner, and a 100.0% limited partner interest to our sponsor, our organizational limited partner.
Initial Public Offering
On August 16, 2012, we completed our initial public offering (“IPO”) of 12,937,500 common units representing limited partner interests in the Partnership at a price to the public of $17.00 per common unit. Total net proceeds paid to our sponsor from the sale of common units in our IPO were $206.5 million after taking into account our underwriting discount.
Acquisition of Hi-Crush Augusta LLC
On January 31, 2013, the Partnership entered into an agreement with our sponsor to acquire a preferred interest in Hi-Crush Augusta LLC (“Augusta”), the entity that owns our sponsor’s 1,187-acre facility with integrated rail infrastructure, located in Eau Claire County, Wisconsin (the "Augusta facility"), for $37.5 million in cash and 3,750,000 newly issued convertible Class B units in the Partnership. Our sponsor did not receive distributions on the Class B units until certain thresholds were met and they converted into common units. The conditions precedent to conversion of the Class B units were satisfied upon payment of our distribution on August 15, 2014 and, upon such payment, 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 sponsor received a per unit distribution on the converted common units for the second quarter of 2014 in an amount equal to the per unit distribution that was paid to all the common and subordinated units for the same period.
On April 8, 2014, the Partnership entered into a contribution agreement with our sponsor to acquire substantially all of the remaining equity interests in our sponsor’s Augusta facility for cash consideration of $224.25 million (the “Augusta Contribution”). To finance the Augusta Contribution and refinance the Partnership’s revolving credit facility, (i) on April 8, 2014, the Partnership commenced a primary public offering of 4,250,000 common units representing limited partnership interests in the Partnership and (ii) on April 28, 2014, the Partnership entered into a $200.0 million senior secured term loan facility with certain lenders. The Partnership’s primary public offering closed on April 15, 2014. On May 9, 2014, the Partnership issued an additional 75,000 common units pursuant to the partial exercise of the underwriters' over-allotment option in connection with the April 2014 primary public offering. Net proceeds to the Partnership from the primary offering and the exercise of the over-allotment option totaled $170.7 million. Upon receipt of the proceeds from the public offering on April 15, 2014, the Partnership paid off the outstanding balance of $124.75 million under its revolving credit facility. The Augusta Contribution closed on April 28, 2014, and at closing, the Partnership’s preferred equity interest in Augusta was converted into common equity interests of Augusta. Following the Augusta Contribution, the Partnership owns 98.0% of Augusta’s common equity interests. In addition, on April 28, 2014, the Partnership entered into a $150.0 million senior secured revolving credit facility with various financial institutions by amending and restating its prior $200.0 million revolving credit facility.
Acquisition of D & I Silica, LLC
On June 10, 2013, the Partnership acquired an independent frac sand supplier, D & I Silica, LLC (“D&I”), transforming the Partnership into an integrated Northern White frac sand producer, transporter, marketer and distributor. The Partnership acquired D&I for $95.2 million in cash and 1,578,947 common units. 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.






3


Overview
We are a pure play, low-cost, domestic producer and supplier of premium 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 consist of “Northern White” sand, a resource existing predominately in Wisconsin and limited portions of the upper Midwest region of the United States, which is highly valued as a preferred proppant because it exceeds all American Petroleum Institute (“API”) specifications. We own, operate and develop sand reserves and related excavation and processing facilities and will seek to acquire or develop additional facilities. Our 751-acre facility with integrated rail infrastructure, located in Wyeville, Wisconsin (the “Wyeville facility”) enables us to process and cost-effectively deliver approximately 1,600,000 tons of 20/70 frac sand per year. We also own a 98.0% interest in Augusta, the entity that owns the Augusta facility, which enables us to process and cost-effectively deliver a further 2,600,000 tons of 20/70 frac sand per year. We operate through an extensive logistics network of rail-served origin and destination terminals located in the Midwest near supply sources and strategically throughout Pennsylvania, Ohio, New York and Texas.
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 more and 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 has increased rapidly, growing at an average annual rate of 26.4% from 2008 to 2013, with total annual sales of $5.0 billion in 2013, according to The Freedonia Group, Inc. We believe that the market for raw frac sand will continue to grow over the long-term based on the expected development of North America’s unconventional oil and natural gas reservoirs and the previously highlighted market dynamics.
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 assets. We expect to have the opportunity to acquire significant additional acreage and reserves currently owned or under an agreement to be acquired by our sponsor, including our sponsor's 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. Our sponsor will not, however, be required 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.
Assets and Operations
We own and operate the Wyeville facility, which is located in Monroe County, Wisconsin and, as of December 31, 2014, contained 75.5 million tons of proven recoverable reserves of frac sand meeting API specifications. We also own a 98.0% interest in the Augusta facility, which is located in Eau Claire County, Wisconsin and, as of December 31, 2014, contained 45.0 million tons of proven recoverable reserves of frac sand meeting API specifications. 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 coarse grade “Northern White” sand exceeding API specifications. Analysis of our sand by independent third-party testing companies indicates that it demonstrates characteristics in excess of API 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). We operate through an extensive logistics network of rail-served origin and destination terminals located in the Midwest near supply sources and strategically throughout Pennsylvania, Ohio, New York and Texas. As of December 31, 2014, we leased or owned 2,721 railcars used to transport our sand from origin to destination and managed a fleet of approximately 4,500 additional railcars dedicated to our facilities by our customers or the Class I railroads. As of January 1, 2015, we had contracted approximately 88% of the annual combined processing capacity of the Wyeville, Augusta and Whitehall facilities for 2015.
Wyeville Facility
We acquired the Wyeville acreage and commenced construction of the Wyeville facility in January 2011. We completed construction of the Wyeville facility and commenced sand excavation and processing in June 2011 with an initial plant processing capacity of 950,000 tons per year, and customer shipments were initiated in July 2011. We completed an expansion in March 2012 that increased our annual processing capacity to approximately 1,600,000 tons of 20/70 frac sand per year. The additional expansion to allow us to produce 100 mesh sand at our Wyeville facility was completed in 2013, which increased our annual processing capacity for all grades of sand to approximately 1,850,000 tons per year. Assuming production at the rated capacity of 1,850,000 tons per year for all grades of sand, 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, 2014.


4


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 our product from the Wyeville facility is shipped by rail from our three 5,000-foot rail spurs that connect our processing and storage facilities to a Union Pacific Railroad mainline. The length of 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
During 2012, our sponsor acquired the Augusta acreage, completed construction and commenced customer shipments, with an initial plant processing capacity of 1,600,000 tons per year. We completed an expansion in December 2014 that increased our annual processing capacity to approximately 2,600,000 tons of 20/70 frac sand per year. Although the additional expansion to allow us to produce 100 mesh sand at our Augusta facility was completed in 2014, the proven reserves determination for our Augusta facility contained in the reserve report prepared by John T. Boyd has not been adjusted to contemplate the sale of 100 mesh sand because John T. Boyd requires additional data on actual process yield before making such an adjustment.  Assuming production at the rated capacity of 2,600,000 tons of 20/70 frac sand per year, and based on a reserve report prepared by John T. Boyd, our Augusta facility has an implied reserve life of 17 years as of December 31, 2014.
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, 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 our product from the Augusta facility is shipped by rail from our three 5,000-foot rail spurs that connect our processing and storage facilities to a Union Pacific Railroad mainline. The length of 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.
Sponsor's Whitehall Facility
During 2013, our sponsor purchased land in Independence and Whitehall, Wisconsin, and in 2014 completed the construction of the Whitehall facility with a rated capacity of 2,600,000 tons of 20/70 frac sand per year. Customer shipments were initiated in September 2014. During 2014, the Partnership purchased 494,206 tons from our sponsor's Whitehall facility. The proven reserves determination for the Whitehall facility contained in the reserve report prepared by John T. Boyd has not been adjusted to contemplate the sale of 100 mesh sand because John T. Boyd requires additional data on actual process yield before making such an adjustment.  Assuming production at the rated capacity of 2,600,000 tons of 20/70 frac sand per year, and based on a reserve report prepared by John T. Boyd, the Whitehall facility has an implied reserve life of 30 years as of December 31, 2014.
Destination Terminal Facilities
As of December 31, 2014, we operated 14 destination rail-based terminal locations throughout the Marcellus and Utica shales and the Permian basin. Our destination terminals include approximately 325,300 tons of rail storage capacity and we are currently in the process of expanding our silo storage capacity by more than 70,000 tons, which will result in over 100,000 tons of silo storage capacity. Our Minerva, Pittston, Smithfield and Wellsboro terminals are capable of accommodating unit trains. 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 most 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.






5


Competitive Strengths
We believe that we are well positioned to successfully execute our strategy and achieve our primary business objective of increasing our cash distributions per unit over time because of the following competitive strengths:
Long-term contracted cash flow. We generate a substantial portion of our revenues from the sale of frac sand under long-term contracts that require our customers to pay specified prices for specified volumes of product each month. We believe the volume requirements and pricing provisions and the long-term nature of our contracts provide us with a stable base of cash flows and limit the risks associated with price movements in the spot market and any changes in product demand during the contract period. As of January 1, 2015, we had contracted to sell 6.6 million tons of frac sand in 2015, with an average remaining contractual term of 4.2 years.
Long-lived, high quality reserve base. Our facilities contain approximately 120.5 million tons of proven recoverable saleable coarse grade reserves as of December 31, 2014, based on third-party reserve reports by John T. Boyd, and have an implied average reserve life of 27 years, assuming production at the rated capacity of 4,450,000 tons per year. 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. We also have the ability to acquire additional reserves contiguous to our plants.
Intrinsic logistics and infrastructure advantage. The strategic location and logistics capabilities of our Wyeville and Augusta facilities and our sponsor's Whitehall facility enable us to serve all major U.S. and Canadian oil and natural gas producing basins. At each of our Wyeville and Augusta facilities, our on-site transportation assets include three 5,000-foot rail spurs off a Union Pacific Railroad mainline that are capable of accommodating unit trains, allowing our customers to receive priority scheduling, expedited delivery and a more cost-effective shipping alternative. The on-site transportation assets at our sponsor's Whitehall facility include an on-site rail yard that contains approximately 30,000 feet of track off a Canadian National Railroad mainline that is capable of accommodating unit trains. Our logistics capabilities enable efficient loading of sand and minimize rail car turnaround times at the facility. 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 a facility 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-served destination terminals strategically located throughout Pennsylvania, Ohio, New York and Texas to serve our customers' operations in the Marcellus and Utica shales and the Permian basin. Our extensive distribution network allows us to better service our customers’ short-notice needs in these basins and provide our customers with solutions to the logistical challenges presented by the large volume of sand required for each fracturing job. To further enhance our customer service in the basins, we anticipate opening additional rail-served destination terminals in 2015.
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. Our sand reserves at the Wyeville facility do not require blasting or crushing to be processed and, due to the shallow overburden at both our Wyeville and Augusta facilities, we are able to use surface mining equipment in our operations, which provides for a lower cost structure than underground mining operations. Our mining operations are subcontracted to Gerke Excavating, Inc. at a fixed cost per ton excavated, subject to a diesel fuel surcharge. 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 the reduction in sand quality due to handling.
Experienced and incentivized management team. Our management team has extensive experience investing and operating in the oil and natural gas industry and is focused on optimizing our current business and expanding our operations through disciplined development and accretive acquisitions. We believe our management team’s substantial experience and relationships with participants in the oilfield services and exploration and production industries provide us with an extensive operational and commercial understanding of the markets in which our customers operate. The expertise of our management and operations teams covers a wide range of disciplines, with an emphasis on development, construction and operation of frac sand processing and terminal facilities, frac sand supply chain management and consulting, and bulk solids material handling. Members of our management team are strongly incentivized to profitably and prudently grow our business and cash flows through their 18% direct and indirect ownership interest in our limited partnership units, and their 39% interest in our sponsor, which owned all of our subordinated units and incentive distribution rights as of February 27, 2015.

6


Business Strategies
Our primary business objective is to increase our cash distributions per unit over time. We intend to accomplish this objective by executing the following strategies:
Focusing on stable, long-term contracts with key customers. A key component of our business model is our contracting strategy, which seeks to secure a high percentage of our cash flows under long-term contracts that require our customers to pay a specified price for a specified volume of frac sand each month. We believe this contracting strategy mitigates our exposure to the potential price volatility of the spot market for frac sand in the short-term, allows us to take advantage of any increase in frac sand prices over the medium-term and provides us with long-term cash flow stability. As current contracts expire or as we add new processing capacity, we intend to pursue similar long-term contracts with our current customers and with other leading pressure pumping service providers. We intend to utilize a substantial majority of our processing capacity to fulfill these contracts, with any excess processed frac sand sold to existing and new customers through our distribution network.
Pursuing accretive acquisitions from our sponsor and third parties. On April 28, 2014, the Partnership entered into a contribution agreement with our sponsor to acquire substantially all of the remaining equity interests in our sponsor’s Augusta facility. On June 10, 2013, we acquired D&I, which now operates through an extensive logistics network of rail-served origin and destination terminals located in the Midwest near supply sources and strategically throughout Pennsylvania, Ohio, New York and Texas. We expect to continue pursuing accretive acquisitions of frac sand facilities from our sponsor, as well as from third-party frac sand production and/or distribution 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.
Expanding our proved reserve base and processing capacity. We seek to identify and evaluate economically attractive expansion and facility enhancement opportunities to increase our proved reserves and processing capacity. We expect to pursue add-on acreage acquisitions near our Wyeville and Augusta facilities to expand our reserve base and increase our reserve life. We completed an additional expansion of our Wyeville and Augusta facilities in 2013 and 2014, respectively, allowing us to produce 100 mesh sand. In addition, during 2014 we expanded the production capacity of the Augusta facility by an additional 1.0 million tons per annum. We will continue to analyze and pursue organic expansion efforts that will similarly allow us to cost-effectively optimize our existing assets and meet the customer demand for our high quality frac sand.
Expanding our distribution network. We seek to identify and evaluate destination 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. At our existing and future sites, we expect to pursue additional storage capabilities to enhance our ability to meet short-term customer demands for the various mesh sizes of frac sand and capitalize on unit train efficiencies. 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.
Capitalizing on compelling industry fundamentals. We intend to continue to position ourselves as a leading producer of high quality frac sand, as we believe the frac sand market offers attractive growth fundamentals over the long-term. The growth in horizontal drilling in the various North American shale plays 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 demand is underpinned by increased horizontal drilling, higher proppant use per well and cost advantages over resin-coated sand and manufactured ceramics. We believe frac sand supply will continue to 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.
Maintaining financial flexibility and conservative leverage. We plan to pursue a disciplined financial policy and maintain a conservative capital structure. As of February 20, 2015, our senior secured term loan facility that permits aggregate borrowings of $200.0 million was fully drawn and we had $25.0 million of outstanding indebtedness and $118.8 million of undrawn borrowing capacity ($150.0 million, net of $25.0 million of indebtedness and $6.2 million letter of credit commitments) under our revolving credit facility. The revolving credit facility is available to fund working capital and general corporate purposes, including the making of certain restricted payments permitted therein. Borrowings under our revolving credit facility are secured by substantially all of our assets. 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.


7


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. We relied on Industry Study #3160, Well Stimulation Materials, June 2014 (“The Freedonia Group Report”), an industry report provided by The Freedonia Group, Inc., a leading international business research company, as our primary source for third-party industry data. 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.
The Freedonia Group Report pertains to North American proppant industry data through the year ended December 31, 2013. Reference herein to 2014 proppant pricing is based on our own observations, internal estimates, and consultations with third parties. We believe that such data, as it relates to the proppants industry, is accurate and we have included such 2014 pricing observations in this Annual Report on Form 10-K.
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. According to the Freedonia Group Report, raw frac sand comprised 81% of the total proppant (by weight) consumed during 2013.
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 may be used as a proppant in all but the highest pressure and temperature drilling environments, such as in the Haynesville Shale, and 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 considered to be of higher quality than Brady Brown and is known for its high crush strength, turbidity, roundness and sphericity and monocrystalline grain structure. Brady Brown has historically been considered the lower quality raw frac sand, as it is less monocrystalline in nature, more angular, has lower crush strength and often contains greater impurities, including feldspars and clays. Due to its quality, Northern White frac sand commands premium prices relative to Brady Brown. 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.


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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. The strength and shape of the end product are largely determined by the quality of the underlying raw frac sand. 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. In general, resin-coated frac sand is better suited for higher pressure, higher temperature drilling operations commonly associated with deep wells and natural gas wells. In 2014, pricing for resin-coated frac sand was generally three to five times the price of raw frac sand.
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. As a result, ceramic proppant use is most applicable in the highest pressure and temperature drilling environments, such as the Haynesville Shale. 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. The deepest, highest temperature and highest pressure wells typically require heavy weight ceramics with high alumina/bauxite content and coarser mesh sizes. The lower crush resistant ceramic proppants are lighter weight and derived from kaolin clay, with densities closer to raw frac sand. In 2014, pricing for ceramic proppants has decreased from more than 10 times the price of raw frac sand to generally more than five times the price of raw frac sand, with bauxite-based, heavy grade ceramics commanding the highest prices.
Comparison of Key Proppant Characteristics
The following table sets forth what we believe to be the key comparative characteristics of our frac sand and the three primary types of proppant.
Products and Characteristics
Hi-Crush Partners LP
 
Raw Frac Sand
 
Resin-Coated
 
Ceramics
•  Natural resource–Northern White sand, which is considered highest quality raw frac sand
 
• Natural resource, primary types include Northern White, Brady Brown
 
• Raw frac sand substrate with resin coating; Bond together to prevent proppant flowback
 
• Manufactured product
• Monocrystalline in nature, exhibiting crush strength, turbidity and roundness and sphericity in excess of API specifications
 
• Quality of sand varies widely depending on source
 
• Coating increases crush strength
 
• Typically highest crush strength
• Crush strength for 30/50 and 40/70 frac sand of 8,000 to 10,000 psi
 
• Crush strength for 30/50 and 40/70 frac sand typically between 5,000 to 10,000 psi
 
• Crush strength of 10,000 to 15,000 psi
 
• Crush strength of 10,000 to 18,000 psi
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. Generally, larger grain sizes are used in wells targeting oil and liquids-rich formations, and smaller grain sizes are used in wells targeting primarily gas bearing formations. 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 are contracted to sell 20/40, 30/50, 40/70 and 100 mesh frac sand used in the hydraulic fracturing process.




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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, with additional procedures used when contaminants are not easily removable. 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 customers by truck, rail or barge. For bulk raw frac sand, transportation costs often represent a significant portion of the customer’s overall product cost. Consequently, shipping in large quantities, particularly 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 our product from our Wyeville and Augusta facilities is shipped by rail from each facility's three 5,000-foot rail spurs that connect our processing and storage facilities to a Union Pacific Railroad mainline. All of the product from our sponsor's Whitehall facility is shipped by rail from an on-site rail yard that contains approximately 30,000 feet of track off a Canadian National Railroad mainline that is capable of accommodating unit trains. The length of these rail spurs 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.
Transportation costs can be a large part of the final proppant cost for end users.  As a result, designing and using an optimized logistics system is a key strategy for many proppant suppliers, including us.  As locating proppant production close to key markets is not always possible, proppant suppliers will often have transload facilities or destination 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.
Demand Trends

According to The Freedonia Group Report, the North American proppant market, including raw frac sand, ceramic and resin coated proppants, was approximately 31 million tons in 2013. Industry estimates for 2013 indicate that the raw frac sand market represented approximately 25 million tons, or 81.0%, of the total proppant market by weight. From 2008 through 2013, proppant demand by weight increased by 26.4% annually and the total North American proppant market size in dollars was $5.0 billion in 2013.
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. 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. According to a January 2015 Baker Hughes, Inc. report, during the five year period beginning January 1, 2010 through December 31, 2014, North American horizontal rig count increased by 18.5% annually. Comparatively, The Freedonia Group Report noted that demand for proppant by weight grew at a rate of 26.4% annually during the five year period ended December 31, 2013. We believe that demand for proppant for each horizontal rig on average has and will continue to increase as a result of the following additional demand drivers:
improved 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 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, the oil and natural gas industry has been shifting away from the use of higher-cost proppants such as ceramics or resin coated sand towards more cost-effective proppants, such as raw frac sand. The substantial increase in activity in North American oil and liquids-rich resource plays has further accelerated the demand growth for raw frac sand. Within these oil and liquids-rich basins, Northern White sand with coarser mesh sizes is often preferred due to its performance characteristics.
Supply Trends
As demand for raw frac sand has increased dramatically in recent years, 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 have announced supply expansions and greenfield projects. However, there are several key 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.
Pricing
We believe raw frac sand has generally exhibited steady price increases over the past decade, reaching a peak in the first half of 2011. Prices were believed to have decreased in the latter half of 2012, reaching a low point in the fourth quarter of 2012.  Since that time, we believe that prices have stabilized and were trending upward throughout 2014 as demand for raw frac sand continued to increase. The outlook for pricing of raw frac sand in 2015 is uncertain, but given the expected declines in rig count and well count, there is likely to be downward pressure on pricing in 2015. There are numerous grades and sizes of proppant which sell at various prices, dependent upon quality, grade of proppant, deliverability and many other factors, including the delivery point.  Pricing of proppant sold at the destination 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 destination terminal. No publicized pricing information for raw sand exists. However, it is believed that the overall pricing trends tend to be consistent across the various sizes. We believe a significant amount of proppant is sold under long-term contracts, with the remainder being sold under short-term pricing agreements.
Customers and Contracts
Our current contracted customer base includes eight of North America’s largest providers of pressure pumping services or their subsidiaries. For the year ended December 31, 2014, sales to each of FTS International, LLC ("FTS International"), Halliburton Company ("Halliburton") and Weatherford International Ltd. ("Weatherford") accounted for greater than 10% of our total revenues.
We sell the majority of the frac sand we produce under long-term contracts that require our customers to pay a specified price for a specified volume of frac sand each month, which reduces our exposure to short-term fluctuations in the price of and demand for frac sand. For the year ended December 31, 2014, we generated 79% of our revenues from frac sand under our long-term contracts. We expect to continue selling a majority of our sand under long-term contracts in 2015 and future years. As of January 1, 2015, we have eight long-term contracts with an average remaining contractual term of 4.2 years and with remaining terms ranging from 24 to 60 months. The following table presents a summary of our contracted volumes and revenues.
 
2011
 
2012
 
2013
 
2014
 
2015
Contracted Volumes (Tons)
331,667

 
1,216,667

 
1,347,500

 
3,789,683

 
6,577,167

% of Processing Capacity (1)
79
%
 
85
%
 
84
%
 
90
%
 
88
%
(1)
Percentage of processing capacity based on weighted average processing capacity for such period and includes the processing capacity of our sponsor's Whitehall facility.


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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 long-term customer contracts contain penalties for non-performance by our customers. If one of our customers fails to meet its minimum obligations to us, we would expect that the make-whole payment, combined with a decrease in our variable costs (such as production costs, royalty payments and transportation costs), would substantially mitigate any adverse impact on our cash flow from such failure. We would also have the ability to sell these sand volumes for which we receive make-whole payments to third parties. 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 three month cure period starting at 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 the contracted volumes and revenues in the above table, we have sold raw frac sand through our distribution network 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 purchase a certain amount of frac sand from various third parties for sale in our distribution network.  A significant portion of this third party sourced frac sand is purchased under contracts that require our suppliers to produce certain quantities and grades of frac sand and specifies the purchase prices for such produced frac sand.
Production Operations
Excavation Operations
The surface excavation operations at our production facilities are conducted by a third-party contractor, Gerke Excavating, Inc. 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 techniques conducted at our Augusta 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. Gerke Excavating, Inc. is paid a fixed fee per ton of sand excavated, subject to a diesel fuel surcharge.
Processing Facilities
Our processing facilities are designed to wash, sort, dry and store our raw frac sand, with each plant employing modern and efficient wet and dry processing technology.
Our mined raw frac sand is initially stockpiled before processing. The material is recovered by a mounted belt feeder, which extends beneath a surge pile and is fed onto a conveyor. The sand exits the tunnel on the conveyor belt and is fed into a 600-ton per hour wet plant at the Wyeville facility and a 900-ton per hour wet plant at the Augusta facility 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. When the wet plants are operating, however, 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 dry plants, which operate year round, have a rated capacity of 250 tons per hour at the Wyeville facility and 400 tons per hour at the Augusta facility. 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.

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Logistics Capabilities
All of our product sold from our production facilities is shipped by rail from three 5,000-foot rail spurs that connect our processing and storage facilities to a Union Pacific Railroad mainline. The product purchased from our sponsor's Whitehall facility is shipped by rail on the Canadian National Railroad mainline from an on-site rail yard that contains approximately 30,000 feet of track and has storage capacity for 500 or more rail cars. The length of these rail spurs and the capacity of the associated product storage silos allow us to accommodate a large number of rail cars, including units 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 require sufficient acreage, loading facilities and rail spurs to accommodate a unit train on site.
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 5,000 foot 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 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
As of December 31, 2014, we operated 14 destination rail-based terminal locations throughout Pennsylvania, Ohio, New York and Texas. Each terminal location in the Marcellus and Utica shales 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 our Minerva, Sheffield, Smithfield and Wellsboro locations, rail-to-storage capabilities.
We generally operate our destination terminal locations under long-term lease agreements with the Class I railroad or applicable short-line rail company. Most 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.
We have an extensive network of Class I and short-line railroads that service our destination terminals. Once the frac sand is loaded into rail cars at the origin, we utilize a combination of Class I and short-line railroads to move the sand to our destination terminals. Frac sand that is transported to our destination terminals by rail is then unloaded to delivery trucks directly via a conveyor. For our Minerva, Sheffield, Smithfield and Wellsboro locations, which comprise our destinations that have silo storage capabilities, frac sand can also be 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. As of December 31, 2014, we had the ability to store 41,600 tons of frac sand in our silos, with additional tons of capacity under construction and expected to be completed in 2015.
Quality Control
We employ an automated process control system that efficiently manages our mining, loading, shipping, storage, processing and preventative maintenance functions. Furthermore, our co-located storage and loading facilities and shipment via unit trains reduce the incidence of contamination during the delivery process and result in higher quality sand being delivered to our customers. We monitor the quality and consistency of our products by conducting hourly tests throughout the production process to detect variances. These tests are conducted on several different machines to ensure that the results are repeatable and accurate. We take product samples from every rail car that is loaded and provide customers with reports per their request. Samples are retained for three months for testing upon customer request. We have a third-party calibration company certify all measurement devices at our facility on a monthly basis. We also provide customers with documentation verifying that all products shipped meet customer specifications. We continually refine our processes to ensure repeatable results in our processing plant and product quality accountability for our customers.
We have established sand testing processes to monitor sand sieve accuracy and turbidity and pre-test all railcars destined for silos at Minerva, Smithfield and Wellsboro. Our testing processes have also been developed to obtain samples from railcars to verify the grade of sand being delivered by railcar.


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Competition
There are numerous large and small producers in all sand producing regions of the United States with which we compete. Our main competitors include:
U.S. Silica Holdings, Inc. (NYSE: SLCA)
Unimin Corporation
Fairmount Minerals, Ltd. (NASDAQ: FMSA)
Emerge Energy Services LP (NYSE: EMES)
Badger Mining Corporation
The most important factors on which we compete are product quality, performance and sand characteristics, transportation capabilities, reliability of supply and price. Demand for frac sand and the prices that we will be able to obtain for our products, to the extent not subject to a long-term contract, 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 raw frac sand and other types of proppants such as resin-coated sand and ceramic proppant.
Our History and Relationship with Our Sponsor
Overview and History
Hi-Crush Proppants LLC, our sponsor, was formed in 2010 in Houston, Texas. Members of our sponsor’s management team have, on average, more than 20 years of experience investing in and operating businesses in the oil and natural gas and sand mining industries. Members of our management team have partnered with major oilfield services companies and exploration and production companies in the development of oil and natural gas reservoirs. In this capacity, members of our management team gained valuable expertise and developed strong relationships in the oilfield services industry. Recognizing the increasing demand for proppants as a result of rapidly evolving hydraulic fracturing techniques, members of our management team chose to leverage their expertise and relationships to capitalize on this increasing demand by developing raw frac sand reserves and facilities. In addition, our Chief Operating Officer has overseen the design, construction and staffing for multiple sand mining and processing facilities. The expertise of our management and operations teams covers a wide range of disciplines, with an emphasis on development, construction and operation of frac sand processing facilities, frac sand supply chain management and consulting, and bulk solids material handling.
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 $3.0 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
In connection with our IPO, our sponsor contributed to us its sand reserves and related excavation and processing facilities located in Wyeville, Wisconsin. On January 31, 2013, we acquired a preferred interest in our sponsor’s Augusta facility and acquired substantially all of the remaining equity interests in the Augusta facility on April 28, 2014.
During 2014, our sponsor constructed its third processing facility, the Whitehall facility, which is capable of producing 2,600,000 tons of 20/70 frac sand per year. In addition, our sponsor is developing its fourth processing facility near Blair, Wisconsin. Our sponsor also has options to acquire several other sand mining locations where it could develop similar production facilities with similar logistics capabilities as its previously constructed facilities.
Our sponsor continually evaluates acquisitions and may elect to acquire, construct or dispose of assets in the future, including in sales of assets to us. As the owner of our general partner, all of our subordinated 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 sand excavation and processing facilities 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.

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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 from its Whitehall facility to us for sale by us to our customers under our long-term contracts and in the spot market. We expect that our sponsor will 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.
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, 2014, Hi-Crush Proppants LLC and its wholly owned subsidiaries had 342 employees. In addition, we contract out our excavation operations to a third party, Gerke Excavating, Inc., 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. The mission of MSHA is to administer the provisions of the Federal Mine Safety and Health Act of 1977 and to enforce compliance with mandatory safety and health standards. As part of MSHA’s oversight, its representatives must perform at least two unannounced inspections annually for each surface mining facility in its jurisdiction. To date, these inspections have not resulted in any citations for material violations of MSHA standards.
We also are subject to the requirements of the U.S. Occupational Safety and Health Act (“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 dust sampling, a respiratory protection program, medical surveillance, training, and other components. Our safety program is designed to ensure compliance with 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 that are involved in establishing, implementing and improving safety standards. We perform annual internal health and safety audits and conduct semi-annual crisis management drills to test our plants’ abilities to respond to various situations.


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Environmental Matters
We and the commercial silica industry are subject to extensive governmental regulation pertaining to matters such as permitting and licensing requirements, plant and wildlife protection, hazardous materials, air and water emissions, and environmental contamination and reclamation. A variety of federal, state and local agencies have established, implement and enforce these regulations.
Federal Regulation
At the federal level, we may be required to obtain permits under Section 404 of the Clean Water Act from the U.S. Army Corps of Engineers for the discharge of dredged or fill material into waters of the United States, including wetlands and streams, in connection with our operations. We also may be required to obtain permits under Section 402 of the Clean Water Act from the EPA or the Wisconsin Department of Natural Resources, 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 Department of Natural Resources, 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” significantly affecting the quality of the human environment. The granting of a federal permit for a major development project, such as a mining operation, may be considered a “major federal action” that requires review under NEPA. 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. The purpose of the NEPA review process is to inform federal agencies’ decision-making on whether federal approval should be granted for a project and to provide the public with an opportunity to comment on the environmental impacts of a proposed project. 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

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agencies also must consider a project’s impacts on historic or archaeological resources under the National Historic Preservation Act, and we may be required to conduct archaeological surveys of project sites and to avoid or preserve historical areas or artifacts.
State and Local Regulation
We are also subject to a variety of state and local environmental review and permitting requirements. Some states, including Wisconsin where our current projects 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.
As demand for frac sand in the oil and natural gas industry has driven a significant increase in current and expected future production of commercial silica, some local communities have expressed concern regarding silica sand mining operations. These concerns have generally included exposure to ambient silica sand dust, truck traffic, water usage, and blasting. In response, certain state and local communities 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 curtail the area available for mining activities, require compensation to local residents for potential impacts of mining activities and, in some cases, ban issuance of new permits for mining activities. There are no operating restrictions in place at our facilities restricting our hours of operations; however, the Augusta facility operates under a noise restriction of up to 60 decibels. We are not aware of any proposals for significant increased scrutiny on the part of state or local regulators in the jurisdictions in which we operate or community concerns with respect to our operations that would reasonably be expected to have a material adverse effect on our business, financial condition, or results of operations going forward.
Planned expansion of our mining and production capacity in new communities could be more significantly impacted by increased regulatory activity. Difficulty or delays in obtaining or inability to obtain new mining permits or 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 the Wyeville and Augusta facilities under a number of federal, state and local authorizations.
Our production facilities currently operate under a construction air permit from the Wisconsin Department of Natural Resources (“Wisconsin DNR”). At our Wyeville facility, we have complied with the construction air permit and have requested an operational air permit from the Wisconsin DNR. At our Augusta facility, we have complied with the construction air permit with respect to several processes, and newly permitted sources are scheduled to be tested in 2015. After demonstrating compliance with the newly

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permitted sources, the Wisconsin DNR will issue an operational air permit. At our production facilities, we 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”) and, at our Augusta facility, also under the Eau Claire County Storm Water Management and Erosion Control ordinance. At our Wyeville facility, an updated Notice of Intent for the WPDES general permit, which will include the new mine areas, was approved by the Wisconsin DNR on August 30, 2013. Placement of all permanent erosion control structures at the Wyeville facility is complete. At our Augusta facility, the placement of all permanent storm water management and erosion control structures at the wet and dry plants and mine facility is complete and those structures are operating under WPDES stormwater operating permits. An updated Notice of Intent for the WPDES general construction permit, which will include modifications to the existing storm water management and erosion control structures for the rail spur expansion, has been submitted and is approved by the Wisconsin DNR. The rail spur is operating under the WPDES stormwater construction permit.
Our production facilities have a U.S. Army Corps of Engineers Section 404 permit and a Wisconsin DNR Section 401 Water Quality Certification for filling of wetlands associated with the rail spur construction. At our Wyeville facility, the Section 404 permit includes the requirement that we restore and monitor 2.1 acres of wetlands at an on-site location per our Compensatory Wetland Mitigation Site Plan. We also obtained a Land Use Permit from Monroe County to fill in and grade a floodplain associated with the rail spur construction. At our Augusta facility, the Section 404 permits include the requirement that we debit 3.29 wetland credits from the Northland Mitigation Bank to provide compensatory mitigation for the 2.80 acres of unavoidable wetland impact. The debit of the aforementioned credits was performed prior to impacting the permitted wetlands. A Letter of Map Amendment was approved by the Federal Emergency Management Agency for a small portion of the rail spur. No remaining sections of the rail spur were shown within the mapped floodplain and no additional permitting was required.
We conduct mining operations at the Wyeville facility pursuant to a Monroe County Nonmetallic Mining Reclamation Permit. We have submitted an updated Nonmetallic Mining Reclamation Plan to Monroe County and have applied for an amendment to the existing permit to address our proposed mine extension. We conduct mining operations at the Augusta facility pursuant to an Eau Claire County Nonmetallic Mining Reclamation Permit. We are in compliance with the permit conditions and Wisconsin Administrative Code NR135.
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.
Safety and Maintenance
We adhere to a strict occupational health program aimed at controlling exposure to silica dust, which includes dust sampling, a respiratory protection program, medical surveillance, training and other components. Our safety program is designed to ensure compliance with the standards of our Occupational Health and Safety Manual and 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.
Availability of Reports; Website Access; Other Information
Our internet address is http://www.hicrushpartners.com. Through “Investor Relations” — “SEC Filings” on our home page, we make available free of charge our Annual Report on Form 10-K, our Quarterly Reports on Form 10-Q, our Current Reports on Form 8-K, SEC Forms 3, 4 and 5 and any amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, or the Exchange Act, as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. 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 the minimum quarterly distribution to our unitholders.
We may not have sufficient cash each quarter to pay the full amount of our minimum quarterly distribution of $0.475 per unit, or $1.90 per unit per year, which will require us to have cash available for distribution of $17.6 million per quarter, or $70.2 million per year, based on the number of common and subordinated units outstanding as of December 31, 2014. The amount of cash we can distribute on our common and subordinated 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 amount of frac sand we are able to excavate and process, which could be adversely affected by, among other things, operating difficulties and unusual or unfavorable geologic conditions;
the volume of frac sand we are able to buy and sell;
the price at which we are able to buy and sell frac sand;
changes in the price and availability of natural gas, diesel fuel or electricity;
changes in prevailing economic conditions, including the extent of changes in natural gas, crude oil and other commodity prices;
unanticipated ground, grade or water conditions;
inclement or hazardous weather conditions, including flooding, and the physical impacts of climate change;
environmental hazards;
difficulties in obtaining and renewing environmental permits;
industrial accidents;
changes in laws and regulations (or the interpretation thereof) related to the mining and hydraulic fracturing industries, silica dust exposure or the environment;
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;
facility shutdowns in response to environmental regulatory actions;
inability to obtain necessary production equipment or replacement parts;
reduction in the amount of water available for processing;
technical difficulties or failures;
labor disputes and disputes with our excavation contractor;
late delivery of supplies;
difficulty collecting receivables;
inability of our customers to take delivery;
changes in the price and availability of transportation;
fires, explosions or other accidents;
cave-ins, pit wall failures or rock falls;
our ability to borrow funds and access capital markets;
changes in the political environment of the drilling basis in which we operate; and
changes in the railroad infrastructure, price, capacity and availability, including the potential for rail line washouts.



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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.
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.
Our long-term business and financial performance depends on the level of drilling and completion activity in the oil and natural gas industry.
Our primary exposure to market risk occurs at the time existing customer contracts expire and are subject to renegotiation, renewal or replacement. Our ability to renew existing customer contracts or enter into new customer contracts on favorable terms is dependent on the market for frac sand at such times. 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.
The number of wells drilled for natural gas increased during 2014 from its lowest level in 13 years as a result of increasing natural gas prices brought on by the higher use of natural gas in heating in the 2013-2014 winter. The number of wells drilled for oil was also increasing for the first several months of 2014 as a result of relatively high prices for oil. However, beginning in July 2014, the price of oil began a steep decline that has continued through February 2015. As a result, the oil and gas rig count has declined to the lowest level since March 2010. This decline could result in a reduction or reversal of the growth rate of oil and gas wells drilled and a decline in the number of oil and gas wells drilled from current levels.
Oil and natural gas producers’ expectations for lower market prices for oil and natural gas, as well as the availability of capital for operating and capital expenditures, may cause them to 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
potential acceleration of development of alternative energy sources.

Crude oil prices declined significantly in the latter half of 2014, and were negatively affected by a combination of factors.  Downward pressure on commodity prices has continued in early 2015 and could continue for the foreseeable future. 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 and 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 (particularly in the Marcellus and Utica shales where a substantial portion of our distribution network is focused), 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 natural gas and oil price environment. If there is a decrease in the demand for frac sand, we may be unable to renew contracts for our products, be forced to renegotiate our existing contracts, or be forced to reduce the prices at which we enter into new contracts, any of which would reduce the amount of cash we generate.

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In addition, to the extent we make sales of our frac sand other than under long-term contracts, the price we receive for those sales will 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.
The majority of our sales are generated under contracts with eight customers, and the loss of, or significant reduction in purchases by, any of them could adversely affect our business, financial condition and results of operations.
As of January 1, 2015, we were contracted to sell raw frac sand under long-term supply agreements to eight customers with remaining terms ranging from 24 to 60 months. More than 50% of our volumes are sold to three of our customers. Upon the expiration of these 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. Furthermore, some of our customers 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 superior logistics or to capture and develop their own sources of frac sand.
In addition, 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 reduction in the amount of frac sand purchased by our customers, renegotiation 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.
Inaccuracies in estimates of volumes and qualities of our sand reserves could result in lower than expected sales and higher than expected production costs.
John T. Boyd, our independent reserve engineers, prepared estimates of our reserves based on engineering, economic and geological data assembled and analyzed by our engineers and geologists. However, frac sand reserve estimates are by nature imprecise and depend to some extent on statistical inferences drawn from available data, which may prove unreliable. There are numerous uncertainties inherent in estimating quantities and qualities of reserves and non-reserve frac sand deposits and costs to mine recoverable reserves, including many factors beyond our control. Estimates of economically recoverable frac sand reserves necessarily depend on a number of factors and assumptions, all of which may vary considerably from actual results, such as:
geological and mining conditions and/or effects from prior mining that may not be fully identified by available data or that may differ from experience;
assumptions concerning future prices of frac sand, operating costs, mining technology improvements, development costs and reclamation costs; and
assumptions concerning future effects of regulation, including the issuance of required permits and taxes by governmental agencies.
Any inaccuracy in John T. Boyd’s estimates related to our frac sand reserves and non-reserve frac sand deposits could result in lower than expected sales and higher than expected costs. For example, John T. Boyd’s estimates of our proven reserves assume that our revenue and cost structure will remain relatively constant over the life of our reserves. If these assumptions prove to be inaccurate, some or all of our reserves may not be economically mineable, which could have a material adverse effect on our results of operations and cash flows. In addition, we pay a fixed price per ton of sand excavated regardless of the quality of the frac sand, and our current customer contracts require us to deliver frac sand that meets certain specifications. If John T. Boyd’s estimates of the quality of our reserves, including the volumes of the various specifications of those reserves, prove to be inaccurate, we may incur significantly higher excavation costs without corresponding increases in revenues, we may not be able to meet our contractual obligations, or our facilities may have a shorter than expected reserve life, which could have a material adverse effect on our results of operations and cash flows.







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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.
The majority of our sales are sourced at our production facilities located in Wyeville, Wisconsin and Augusta, Wisconsin and our sponsor's production facility located near Whitehall, Wisconsin. Any adverse developments at the facilities could have a material adverse effect on our financial condition and results of operations.
The majority of our sales are produced from our production facilities. Any adverse development at these 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 three months of contract year-end, or otherwise arrange for delivery from a third party, we will 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. Further, we purchase a certain amount of frac sand from third parties for use in our distribution network.  Upon expiration of our current contract terms with our frac sand suppliers, we may be unable to renew our existing contracts or enter into new contracts on terms favorable to us, or at all.  If we are unable to provide supply from our own facilities, any reduction in the amount of frac sand available for our purchase from third parties, renegotiation of 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.
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.
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, which has been a contributing factor to steadily increasing prices for raw frac sand over the last decade. 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 on favorable terms, 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.

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Federal, state, and local legislative and regulatory initiatives relating to hydraulic fracturing and the potential for related litigation could result in increased costs, additional operating restrictions or delays for our customers, which could cause a decline in the demand for our frac sand and negatively impact our business, financial condition and results of operations.
We supply frac sand to hydraulic fracturing operators in the oil and natural gas industry. Hydraulic fracturing is an important and increasingly common practice that is used to stimulate production of natural gas and/or oil from low permeability hydrocarbon bearing subsurface rock formations. The hydraulic fracturing process involves the injection of water, proppants and chemicals under pressure into the formation to fracture the surrounding rock, increase permeability and stimulate production. Increased regulation of hydraulic fracturing may adversely 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. 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. Several federal agencies, regulatory authorities, and legislative entities are investigating the potential environmental impacts of hydraulic fracturing and whether additional regulation may be necessary. The U.S. Department of the Interior revised new regulations on May 16, 2013, which would require oil and natural gas operators to disclose the chemicals they use during hydraulic fracturing on federal lands. The proposed regulations would also strengthen standards for wellbore integrity and the management of fluids that return to the surface during and after fracturing operations on federal lands. In addition, the U.S. Environmental Protection Agency continues to study the potential environmental impacts of hydraulic fracturing activities and has announced plans to propose standards for the treatment and discharge of wastewater resulting from hydraulic fracturing by 2015. These studies and activities, depending on their results, could spur proposals or initiatives to regulate hydraulic fracturing under the SDWA or otherwise. From time to time Congress has considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process.
In addition, various state, local, and foreign governments have implemented, or are considering, increased regulatory oversight of hydraulic fracturing through additional permitting requirements, operational restrictions, disclosure requirements, and temporary or permanent bans on hydraulic fracturing in certain areas such as environmentally sensitive watersheds. Many local governments also have adopted ordinances to severely restrict or prohibit hydraulic fracturing activities within their jurisdictions.
The adoption of new or more stringent laws or regulations at the federal, state, local, or foreign levels imposing reporting obligations on, or otherwise limiting or delaying, the hydraulic fracturing process could make it more difficult to complete 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.
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. Our long-term contracts require our customers to pay a specified price for a specified volume of frac sand each month. As a result, in periods with increasing prices, our sales may not keep pace with market prices.
Additionally, 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.





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We are exposed 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 in light of the recent decline in oil prices, we are unable to determine whether our customers will 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 use the production could have a material adverse effect on our business, financial condition, results of operations and ability to pay distributions to our unitholders.
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. Certain of the insurance policies covering entities that were contributed to us in connection with our formation and our operations also provide coverage to entities that were not contributed to us by our sponsor. The coverage available under those insurance policies has historically been and is currently allocated among the entities that were contributed to us and those entities that were not contributed to us. We reimburse our sponsor for our allocation of premium costs. This allocation may result in limiting the amount of recovery available to us for purposes of covered losses.
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 have increased and could escalate further. 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.
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, Fairmount Minerals, Ltd., Emerge Energy Services LP and Badger Mining Corporation. 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 exit the market, selling 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.
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, 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-served origin and distribution 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 services utilized by our customers (whether these services are provided by us or a third party), and they are unable to find alternative transportation providers to transport frac sand, our business could be adversely affected.

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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, 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.
Our production process consumes large amounts of natural gas and electricity. An increase in the price or a significant interruption in the supply of these or any other energy sources could have a material adverse effect on our financial condition or results of operations.
Energy costs, primarily natural gas and electricity, represented 2% of our total sales and 11% of our total production costs during the year ended December 31, 2014. 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, from a high of $8.15 per million British Thermal Units (“BTUs”) in February 2014 to a low of $1.82 per million BTUs in April 2012, and this volatility may continue. 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.
Increases in the price of diesel fuel may adversely affect our results of operations.
Diesel fuel costs 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. Accordingly, increased diesel fuel costs could have an adverse effect on our results of operations and 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 currently use 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 facility, 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 significant dilution to our existing unitholders.


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We have entered into a revolving credit facility and senior secured term loan facility which contain restrictions and financial covenants that may restrict our business and financing activities.
Our revolving credit facility 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 facility 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 facility contains covenants requiring us to maintain a leverage ratio of not more than 3.50 to 1.00 and a minimum interest coverage ratio of not less than 2.50 to 1.00. Additionally, our revolving credit facility 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;
pay cash dividends; and
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 facility 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 facility 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.
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 facility and senior secured term loan facility. As of December 31, 2014, we had $196.7 million of debt outstanding, with an effective interest rate of 5.9%. 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.
A facility closure entails substantial costs, and if we close our production facilities sooner than anticipated, our results of operations may be adversely affected.
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 close our production facilities 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. 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 may be 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.

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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 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.
We do not own the land on which the majority of our destination terminal facilities are located, which could disrupt our operations.
We do not own the land on which the majority of our destination terminals are located and instead own leaseholds 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.
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 excavation using modern techniques and equipment requires skilled laborers, preferably with several years of experience and proficiency in multiple tasks, including processing of mined minerals. Our mining operations are subcontracted to Gerke Excavating, Inc., but there is a shortage of skilled mining labor in Wisconsin. If the shortage of experienced labor continues or worsens, we may find it difficult to renew or replace that contract upon its expiration on acceptable terms, 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 expand production.
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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Failure to maintain effective quality control systems at our mining, processing and production 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.
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.
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 comes earlier than expected or lasts 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. While our sales and finished product production levels are contracted evenly throughout the year, our mining and wet sand processing activities are limited to non-winter months. In addition, while the wet processing plant is not operating, we will perform annual maintenance activities, the majority of which are expensed. As a consequence, 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 property, 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.
A terrorist attack or armed conflict could harm our business.
Terrorist activities, anti-terrorist efforts and other armed conflicts involving the United States could adversely affect the United States and global economies and could prevent us from meeting financial and other obligations. We could experience loss of business, delays or defaults in payments from payors or disruptions of fuel supplies and markets if pipelines, production facilities, processing plants or refineries are direct targets or indirect casualties of an act of terror or war. Such activities could reduce the overall demand for oil and natural gas, which, in turn, could also reduce the demand for our frac sand. Terrorist activities and the threat of potential terrorist activities and any resulting economic downturn could adversely affect our results of operations, impair our ability to raise capital or otherwise adversely impact our ability to realize certain business strategies.

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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 U.S. Mining Safety and Health Administration, may continue to propose 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, which imposes 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, as amended by the Mine Improvement and New Emergency Response Act of 2006, which imposes stringent health and safety standards on numerous aspects of mineral extraction and processing operations, including the training of personnel, operating procedures, operating 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 mineral extraction and processing 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 inability to acquire, maintain or renew financial assurances related to the reclamation and restoration of mining property could have a material adverse effect on our business, financial condition and results of operations.
We are generally obligated to restore property in accordance with regulatory standards and our approved reclamation plan after it has been mined. We are required under federal, state, and local laws to maintain financial assurances, such as surety bonds, to secure such obligations. The inability to acquire, maintain or renew such assurances, as required by federal, state, and local laws, could subject us to fines and penalties as well as the revocation of our operating permits. Such inability could result from a variety of factors, including:
the lack of availability, higher expense, or unreasonable terms of such financial assurances;
the ability of current and future financial assurance counterparties to increase required collateral; and
the exercise by financial assurance counterparties of any rights to refuse to renew the financial assurance instruments.
Our inability to acquire, maintain, or renew necessary financial assurances related to the reclamation and restoration of mining property could have a material adverse effect on our business, financial condition, and results of operations.








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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 which, in turn, may affect the ability of the subordinated units to convert;
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, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination period;
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 distributions on our subordinated units or 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 at least $0.475 per unit 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 and could elect to pay lesser distributions or not to pay distributions for one or more quarters.
In addition, our partnership agreement does not require us to pay any distributions at all. Accordingly, investors are cautioned not to place undue reliance on the permanence of such a policy in making an investment decision. Any modification or revocation of our cash distribution policy could substantially reduce or eliminate the amounts of distributions to our unitholders. The amount of distributions we make, if any, and the decision to make any distribution at all will be determined by the board of directors of our general partner, whose interests may differ from those of our common unitholders. Our general partner has limited duties to our unitholders, which may permit it to favor its own interests or the interests of our sponsor to the detriment of our common unitholders.
Our general partner intends to limit its liability regarding our obligations.
Our general partner intends to limit its liability under contractual arrangements between us and third parties so that the counterparties to such arrangements have recourse only against our assets, and not against our general partner or its assets. Our general partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our general partner. Our partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner’s duties, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our general partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders.
Our sponsor 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 Hi-Crush Whitehall LLC, 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 policy 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 plan to 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.



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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 there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (50.0%) 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, 2014, our sponsor owned an aggregate of 36.9% of our common and subordinated units. Also, if our general partner is removed without cause during the subordination period and no units held by the holders of the subordinated units or their affiliates are voted in favor of that removal, all remaining subordinated units will automatically be converted into common units and any existing arrearages on the common units will be extinguished. Cause is narrowly defined in our partnership agreement to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our general partner liable for actual fraud or willful or wanton misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business.
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, 2014, our sponsor owned an aggregate of 36.9% of our common and subordinated units. At the end of the subordination period, assuming no additional issuances of units, our sponsor will own 36.9% 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.
We incur increased costs as a result of being a publicly-traded partnership.
As a publicly-traded partnership, we incur significant legal, accounting and other expenses that we did not incur prior to becoming public. In addition, the Sarbanes-Oxley Act of 2002, as well as rules implemented by the SEC and the NYSE, require publicly-traded entities to adopt various corporate governance practices that further increase our costs. Before we are able to make distributions to our unitholders, we must first pay or reserve cash for our expenses, including the costs of being a publicly-traded partnership. As a result, the amount of cash we have available for distribution to our unitholders is affected by the costs associated with being a public company.







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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 our not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service ("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 our being treated as a partnership for federal income tax purposes.
Despite the fact that we are organized as a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. Although we do not believe, based upon our current operations, that we will be so treated, a change in our business (or a change in current law) could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.
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, which is currently a maximum of 35%, 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 minimum quarterly distribution amount and 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 U.S. federal income tax laws that affect the tax treatment of publicly traded partnerships.  Any modification to the federal income tax laws may be applied retroactively and could make it more difficult or impossible 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 us common units.  We are unable to predict whether any of these changes or any other proposals will ultimately be enacted.  Any such changes could negatively impact the value of an investment in our common units and the amount of cash available for distribution to our unitholders.
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. 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.
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. 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.


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Tax gain or loss on the disposition of our common units could be more or less than expected.
If our unitholders sell their common units, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis in those common units. Because distributions in excess of their allocable share of our net taxable income result in a decrease in their tax basis in their common units, the amount, if any, of such prior excess distributions with respect to the units they sell will, in effect, become taxable income to them if they sell such units at a price greater than their tax basis in those units, even if the price they receive is less than their original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture of depreciation and depletion deductions and certain other items. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if they sell their units, they may incur a tax liability in excess of the amount of cash they receive from the sale.
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.
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 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, instead of on the basis of the date a particular common unit is transferred. Nonetheless, we allocate certain deductions for depreciation of capital additions based upon the date the underlying property is placed in service. The use of this proration method may not be permitted under existing or proposed Treasury Regulations. If the IRS were to successfully challenge our proration method, we may be required to change the allocation of items of income, gain, loss, and deduction among our unitholders.







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A unitholder whose common units are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale of common units) may be considered as having disposed of those common units. If so, such unitholder would no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.
Because there 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.
Our unitholders will likely be 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 could be 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, 2014, we own assets and conduct business in the states of Wisconsin, Pennsylvania, Ohio, New York, West Virginia and Texas. 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 U.S. federal, foreign, state and local tax returns.


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ITEM 1B.       UNRESOLVED STAFF COMMENTS
Not applicable.


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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, 2014, we operated two production facilities located in Wyeville, Wisconsin and Augusta, Wisconsin, of which we own all associated land. In addition, we own and operate 14 destination rail-based terminal locations throughout the Marcellus and Utica shales and the Permian basin and lease or own 2,721 railcars used to transport our sand from origin to destination. Substantially all of our owned assets are pledged as security under our revolving credit facility 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 acquired the Wyeville acreage and commenced construction of the Wyeville facility in January 2011. We completed construction of the Wyeville facility and commenced sand excavation and processing in June 2011 with an initial plant processing capacity of 950,000 tons per year, and customer shipments were initiated in July 2011. We completed an expansion in March 2012 that increased our annual processing capacity to approximately 1,600,000 tons per year. As of December 31, 2014, the total cost of our plant and equipment was $57.1 million. The plant is in good physical condition and includes modern equipment powered by natural gas, electricity and propane fuel.
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 our product from the Wyeville facility is shipped by rail from our three 5,000-foot rail spurs that connect our processing and storage facilities to a Union Pacific Railroad mainline. The length of 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 751 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
 
Shallow overburden allowing for surface excavation.
Sand Processing
 
Sands are unconsolidated; do not require crushing.
Logistics Capabilities
 
On-site transportation infrastructure capable of accommodating unit trains connected to Union Pacific Railroad mainline.
Augusta Facility
During 2012, our sponsor acquired the Augusta acreage, completed construction and commenced customer shipments, with an initial plant processing capacity of 1,600,000 tons per year. We completed an expansion in December 2014 that increased our annual 20/70 frac sand processing capacity to approximately 2,600,000 tons per year. As of December 31, 2014, the total cost of the Augusta facility and equipment was $96.2 million. The plant is in good physical condition and includes modern equipment powered by natural gas, electricity and propane fuel.

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 our product from the Augusta facility is shipped by rail from our three 5,000-foot rail spurs that connect the processing and storage facilities to a Union Pacific Railroad mainline. The length of these rail spurs and the capacity of the associated product storage silos allow the accommodation of a large number of railcars, including unit trains.



41


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.
Distribution Assets
As of December 31, 2014, we operated 14 destination rail-based terminal locations throughout the Marcellus and Utica shales and the Permian basin, as summarized in the following table:
Location
 
Storage Capabilities
 
Railroad
 
Unit Train Capable
 
On-site Laboratory
Binghamton, NY
 
Rail
 
New York Susquehanna & Western Railway
 
 
 
 
Big Spring, TX
 
Rail
 
Big Spring Rail Systems
 
 
 
 
Bradford, PA
 
Rail/Silo
 
Buffalo and Pittsburgh Railroad
 
 
 
 
Dennison, OH
 
Rail
 
Columbus and Ohio River Railroad
 
 
 
 
Driftwood, PA
 
Rail
 
Buffalo and Pittsburgh Railroad
 
 
 
 
Greenville, PA
 
Rail
 
Canadian National
 
 
 
 
Kittanning, PA
 
Rail
 
Buffalo and Pittsburgh Railroad
 
 
 
þ
Minerva, OH
 
Rail/Silo
 
Ohi-Rail Corp.
 
þ
 
þ
Mingo Junction, OH
 
Rail (1)
 
Norfolk Southern
 
(1)
 
 
Pittston, PA
 
Rail
 
Reading Blue Mountain & Northern Railroad
 
þ
 
 
Ridgway, PA
 
Rail
 
Buffalo and Pittsburgh Railroad
 
 
 
 
Sheffield, PA
 
Rail/Silo
 
Buffalo and Pittsburgh Railroad
 
 
 
þ
Smithfield, PA
 
Rail/Silo
 
Southwest Pennsylvania Railroad
 
þ
 
þ
Wellsboro, PA
 
Rail/Silo
 
Wellsboro & Corning Railroad
 
þ
 
þ
(1) The Mingo Junction location is currently undergoing an expansion including silos and other equipment to support unit train operations.
As of December 31, 2014, we leased or owned 2,721 railcars used to transport our sand from origin to destination.
Sand Reserves
We own and operate the Wyeville facility, which is located in Monroe County, Wisconsin and, as of December 31, 2014, contained 75.5 million tons of proven recoverable sand reserves. We also own and operate the Augusta facility, which is located in Eau Claire County, Wisconsin and, as of December 31, 2014, contained 45.0 million tons of proven recoverable sand reserves of 20/70 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 and Augusta 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, 2014, and we intend to continue retaining third-party engineers to review our reserves on an annual basis.



42


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.
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 and Augusta 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 some instances in the future, we may acquire the mineral rights to reserves without actually taking ownership of the properties.
An approximately 300 acre portion of the Wyeville acreage is subject to an agreement whereby we agreed to sell such acreage back to the individuals from whom the land was purchased in the event that the applicable minimum royalty payments have not been satisfied. If such minimum royalty payments for the three year period commencing on September 15, 2011 (the “Initial Operations Period”) had not been satisfied before September 15, 2014, we agreed to sell the property to the original landowner for one dollar, subject to certain terms. Additionally, at the end of each 12 month period following the conclusion of the Initial Operations Period, if such minimum royalties have not been satisfied for the rolling three previous years (the “Subsequent Operations Periods”), we agreed to sell the property to the original landowner for one dollar, subject to certain terms.
During any Subsequent Operations Period, the required royalty payments amount to an aggregate of $1,050,000 over each three year period. During the Initial Operations Period, we paid aggregate royalty payments to the original landowner in excess of the minimum requirement. If we have not made the minimum required royalty payments associated with ongoing sand sales by the end of any Subsequent Operations Period, we may satisfy our obligation by making a lump-sum cash make-whole payment. Accordingly, we believe there is no material risk that we will be required to sell back the subject property pursuant to this agreement.







43


Summary of Reserves
The following table provides a summary of our Wyeville and Augusta facilities, and our sponsor's Whitehall facility, as of December 31, 2014:
Mine/Plant Location         
 
Owned/Leased      
 
Area (in acres)    
 
Proven Reserves (in thousands)  
 
Primary End Markets Served    
Wyeville, WI
 
Owned
 
751
 
75,450
 
Oil and gas proppants
Augusta, WI*
 
Owned
 
1,187
 
45,035
 
Oil and gas proppants
Whitehall, WI**
 
Owned
 
1,447
 
78,941
 
Oil and gas proppants
*Our sponsor owns 2% of Hi-Crush Augusta LLC, the entity that owns the Augusta facility.
**Our sponsor owns 100% of the Whitehall facility.


44


ITEM 3.       LEGAL PROCEEDINGS
Legal Proceedings
In addition to the matters described below, we are subject to various 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. 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.
Following the Partnership’s November 2012 announcement that Hi-Crush Operating LLC had formally terminated its supply agreement with Baker Hughes in response to the repudiation of the agreement by Baker Hughes, the Partnership, our general partner, certain of its officers and directors and its underwriters were named as defendants in purported securities class action lawsuits brought by the Partnership’s unitholders in the United States District Court for the Southern District of New York. On February 11, 2013, the lawsuits were consolidated into one lawsuit, styled In re: Hi-Crush Partners L.P. Securities Litigation, No. 12-Civ-8557 (CM). A consolidated amended complaint was filed on February 15, 2013. That complaint asserted claims under sections 11, 12(a)(2), and 15 of the Securities Act of 1933, as amended, or the Securities Act, and sections 10(b) and 20(a) of the Exchange Act in connection with the Partnership’s Registration Statement and a subsequent presentation. Among other things, the consolidated amended complaint alleges that defendants failed to disclose to the market certain alleged information relating to Baker Hughes’ repudiation of the supply agreement. On March 22, 2013, the Partnership filed a motion to dismiss the complaint. On December 2, 2013, the court issued an order dismissing the claims relating to the Partnership’s Registration Statement, but did not dismiss the claims relating to alleged misrepresentations concerning the Partnership’s relationship with Baker Hughes after the IPO. On September 12, 2014, the parties entered into a Stipulation of Settlement (the "Settlement") providing for the settlement of the consolidated action and release of all claims for $3.8 million, subject to the court's approval. On January 5, 2015, the court issued a final Approval Order approving the proposed Settlement and dismissing with prejudice the complaints contained in the consolidated action.
On December 20, 2013, Stephen Bushansky, a purported unitholder of the Partnership, filed a lawsuit, derivatively on behalf of the Partnership, against our general partner and certain of its officers and directors, in an action styled Bushansky v. Hi-Crush GP LLC, Cause No. 2013-76463, in the 215th Judicial District Court, Harris County, Texas. The lawsuit alleged that by failing to disclose Baker Hughes’ attempted repudiation of its supply agreement with Hi-Crush Operating LLC prior to the Partnership’s November 2012 announcement terminating the agreement, defendants failed to design and implement an effective system of internal controls to prevent the Partnership from violating federal securities laws. Plaintiff asserted a claim for breach of fiduciary duties of good faith, care, loyalty, reasonable inquiry, oversight and supervision. Plaintiff also asserted that the defendants aided and abetted in one another’s breaches of fiduciary duties and seeks relief from defendants on the theory of indemnity for all damages that occurred as a result of defendants’ alleged violations. On January 29, 2014, defendants filed a motion to dismiss, plea to the jurisdiction, or in the alternative, motion to stay based on the mandatory contractual forum selection clause in our partnership agreement. On March 7, 2014, the court granted defendants' action to dismiss without prejudice.


45


ITEM 4.       MINE SAFETY DISCLOSURES.
We adhere to a strict occupational health program aimed at controlling exposure to silica dust, which includes dust sampling, a respiratory protection program, medical surveillance, training and other components. 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.


46


PART II


47


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.” Initial trading of our common units commenced on August 16, 2012. Accordingly, no market for our units existed prior to that date.
The following tables 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, 2013
 
$
19.82

 
$
15.00

June 30, 2013
 
$
24.24

 
$
17.44

September 30, 2013
 
$
27.44

 
$
20.26

December 31, 2013
 
$
38.75

 
$
25.07

March 31, 2014
 
$
42.05

 
$
33.65

June 30, 2014
 
$
65.70

 
$
36.89

September 30, 2014
 
$
71.88

 
$
51.45

December 31, 2014
 
$
55.71

 
$
28.92

Cash Distributions To Common And Subordinated Unitholders:
For the Quarter Ended
 
Record Date
 
Payment Date
 
Amount per
Limited Partner  
Unit
March 31, 2013
 
May 1, 2013
 
May 15, 2013
 
$
0.4750

June 30, 2013
 
August 1, 2013
 
August 15, 2013
 
$
0.4750

September 30, 2013
 
November 1, 2013
 
November 15, 2013
 
$
0.4900

December 31, 2013
 
January 31, 2014
 
February 14, 2014
 
$
0.5100

March 31, 2014
 
May 1, 2014
 
May 15, 2014
 
$
0.5250

June 30, 2014
 
August 1, 2014
 
August 15, 2014
 
$
0.5750

September 30, 2014
 
October 31, 2014
 
November 14, 2014
 
$
0.6250

December 31, 2014
 
January 30, 2015
 
February 13, 2015
 
$
0.6750

As of December 31, 2014, there were 23,312,075 common units outstanding held by approximately 35,808 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, 2014, we had also issued 13,640,351 subordinated units, for which there is no established public market in which such units are exchanged. All of the subordinated units are held by our sponsor.
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 our minimum quarterly distribution rate or at any other 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 facility and senior secured term loan facility, which contain financial tests and covenants that we must satisfy. 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.

48


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, subordinated 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 and would result in a reduction in the minimum quarterly distribution and the target distribution levels.
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 the Minimum Quarterly Distribution
Within 60 days after the end of each quarter, we intend to distribute to the holders of common and subordinated units on a quarterly basis at least the minimum quarterly distribution of $0.4750 per unit, or $1.90 on an annualized basis, 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. The distribution made on November 15, 2012 represented a proration of our minimum quarterly distribution of $0.4750 per unit for the period from August 16, 2012 to September 30, 2012.
Even if our cash distribution policy is not modified or revoked, the amount of distributions paid under our policy and the decision to make any distribution is determined by our general partner. 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 the minimum 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.
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, 2014.
Recent Sales of Unregistered Securities
On May 8, 2012, in connection with our formation, we issued (i) the non-economic general partner interest in us to our general partner and (ii) the 100.0% limited partner interest in us to our sponsor for $1,000.00. The issuance was exempt from registration under Section 4(2) of the Securities Act.
On January 30, 2013, we issued 5,522 common units to our independent directors, Mr. Winkler III and Mr. Affleck-Graves.

49


On January 31, 2013, in connection with our acquisition of a preferred equity interest in Hi-Crush Augusta LLC, we issued 3,750,000 Class B units to our sponsor. The Class B units converted to common units on August 15, 2014. The issuance was exempt from registration under Section 4(2) of the Securities Act.
On June 10, 2013, the Partnership issued 1,578,947 common units in connection with its acquisition of D&I.
On January 8, 2014, we issued 4,149 common units to our independent directors, Mr. Winkler III, Mr. Affleck-Graves and Mr. Poorman.
On June 26, 2014, we issued 1,383 common units to one of our directors, Mr. Huff.
During 2014, we issued 7,022 restricted common units to certain employees.
On January 8, 2015, we issued 6,344 common units to our independent directors, Mr. Winkler III, Mr. Affleck-Graves and Mr. Poorman, and to Mr. Huff.
Purchase of Equity Securities by the Issuer and Affiliated Purchasers
On August 1, 2014, we purchased 299 common units from employees.
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, 2014.


50


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.
 
Year Ended December 31, 2014
 
Year Ended December 31, 2013
 
Period From August 16 Through December 31, 2012
 
Period From January 1 Through August 15, 2012
 
Year Ended December 31, 2011
 
Inception to December 31, 2010
(in thousands, except tons, per ton and per unit amounts)
Successor
 
Successor
 
Successor
 
Predecessor
 
Predecessor
 
Predecessor
Statement of Operations Data:
 
 
 
 
 
 
 
 
 
 
 
Revenues
$
386,547

 
$
178,970

 
$
31,770

 
$
46,776

 
$
20,353

 
$

Production costs
58,452

 
41,999

 
8,944

 
12,247

 
5,998

 

Other cost of sales
156,904

 
46,688

 

 

 

 

Depreciation and depletion
10,628

 
7,197

 
1,109

 
1,089

 
449

 

Cost of goods sold
225,984

 
95,884

 
10,053

 
13,336

 
6,447

 

Gross profit
160,563

 
83,086

 
21,717

 
33,440

 
13,906

 

Operating costs and expenses:
 
 
 
 
 
 
 
 
 
 
 
General and administrative
26,346

 
19,096

 
3,757

 
4,631

 
2,324

 
26

Exploration expense

 
47

 
121

 
539

 
381

 

Accretion expense
246

 
228

 
102

 
16

 
28

 

Income (loss) from operations
133,971

 
63,715

 
17,737

 
28,254

 
11,173

 
(26
)
Other income (expense):
 
 
 
 
 
 
 
 
 
 
 
Other income

 

 

 
6

 

 

Interest expense
(9,946
)
 
(3,671
)
 
(320
)
 
(3,240
)
 
(1,893
)
 

Net income (loss)
124,025

 
60,044

 
17,417

 
25,020

 
9,280

 
(26
)
(Income) loss attributable to non-controlling interest
(955
)
 
(274
)
 
23

 

 

 

Net income (loss) attributable to Hi-Crush Partners LP
$
123,070

 
$
59,770

 
$
17,440

 
$
25,020

 
$
9,280

 
$
(26
)
Earnings per unit:
 
 
 
 
 
 
 
 
 
 
 
Common and subordinated units - basic
$
3.09

 
$
2.08

 
$
0.68

 
 
 
 
 
 
Common and subordinated units - diluted
$
3.00

 
$
2.08

 
$
0.68

 
 
 
 
 
 
Distributions per unit:
 
 
 
 
 
 
 
 
 
 
 
Common units
$
2.4000

 
$
1.9500

 
$
0.7125

 
 
 
 
 
 
Subordinated units
$
2.4000

 
$
1.9500

 
$
0.7125

 
 
 
 
 
 
Statement of Cash Flow Data:
 
 
 
 
 
 
 
 
 
 
 
Net cash provided by (used in):
 
 
 
 
 
 
 
 
 
 
 
Operating activities
$
104,370

 
$
64,323

 
$
14,498

 
$
16,660

 
$
18,788

 
$
(14
)
Investing activities
(264,715
)
 
(105,585
)
 
(8,218
)
 
(80,045
)
 
(50,199
)
 
(322
)
Financing activities
144,383

 
51,372

 
2,234

 
61,048

 
42,465

 
336

Other Financial Data:
 
 
 
 
 
 
 
 
 
 
 
EBITDA (1)
$
148,015

 
$
73,534

 
$
18,846

 
$
29,349

 
$
11,622

 
$
(26
)
Capital expenditures (2)
40,465

 
10,630

 
8,218

 
80,075

 
50,169

 
72

Operating Data:
 
 
 
 
 
 
 
 
 
 
 
Total tons sold
4,584,811

 
2,520,119

 
481,208

 
726,213

 
332,593

 

Average realized price (per ton sold)
$
70.46

 
$
65.64

 
$
66.02

 
$
64.41

 
$
61.19

 
$

Sand produced and delivered (in tons)
3,704,630

 
2,241,199

 
481,208

 
726,213

 
332,593

 

Production costs (per ton produced and delivered)
15.78

 
18.74

 
18.59

 
16.86

 
18.03

 

Balance Sheet Data (at period end)
 
 
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
4,646

 
$
20,608

 
$
10,498

 
$
8,717

 
$
11,054

 
$

Total assets
436,120

 
354,361

 
189,397

 
175,828

 
72,229

 
614

Long-term debt (includes current portion)
198,364

 
138,250

 

 
111,402

 
46,112

 

Total liabilities
257,679

 
171,007

 
94,270

 
140,747

 
61,942

 
304

Equity
178,441

 
183,354

 
95,127

 
35,081

 
10,287

 
310

(1)
For more information, please read “Non-GAAP Financial Measures” below.
(2)
Capital expenditures made to increase the long-term operating capacity of our asset base whether through construction or acquisitions.


51


Non-GAAP Financial Measures
EBITDA
We define EBITDA as net income plus depreciation, depletion and amortization and interest and debt expense, net of interest income. EBITDA is not a presentation made in accordance with GAAP.
EBITDA is a 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 will provide useful information to investors in assessing our financial condition and results of operations. The GAAP measure most directly comparable to EBITDA is net income. Our non-GAAP financial measure of EBITDA should not be considered as an alternative to GAAP net income. 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 in isolation or as a substitute for analysis of our results as reported under GAAP. Because EBITDA may be defined differently by other companies in our industry, our definition of EBITDA may not be comparable to similarly titled measures of other companies, thereby diminishing its utility.
Distributable Cash Flow
We use distributable cash flow to evaluate whether we are generating sufficient cash flow to support distributions to our unitholders. We define distributable cash flow as 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. Distributable cash flow will not reflect changes in working capital balances. EBITDA is a supplemental measure utilized by our management and other users of our financial statements such as investors, commercial banks, research analysts and others, to assess the financial performance of our assets without regard to financing methods, capital structure or historical cost basis. Distributable cash flow is a supplemental measure used to measure the ability of our assets to generate cash sufficient to support our indebtedness and make cash distributions to our unitholders.
















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The following table presents a reconciliation of 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, 2014
 
Year Ended December 31, 2013
 
Period From August 16 Through December 31,  2012  
 
Period From January 1 Through August 15,  2012  
 
Year Ended December 31, 2011  
 
Inception to December 31, 2010
(in thousands)
Successor
 
Successor
 
Successor
 
Predecessor
 
Predecessor
 
Predecessor
Reconciliation of EBITDA and distributable cash flow to net income (loss):
 
 
 
 
 
 
 
 
 
 
 
Net income (loss)
$
124,025

 
$
60,044

 
$
17,417

 
$
25,020

 
$
9,280

 
$
(26
)
Depreciation and depletion expense
8,858

 
6,132

 
1,109

 
1,089

 
449

 

Amortization expense
5,186

 
3,687

 

 

 

 

Interest expense
9,946

 
3,671

 
320

 
3,240

 
1,893

 

EBITDA
$
148,015

 
$
73,534

 
$
18,846

 
$
29,349

 
$
11,622

 
$
(26
)
Less: Cash interest paid
(8,682
)
 
(3,123
)
 
(193
)
 
 
 
 
 
 
Less: (Income) loss attributable to non-controlling interest
(955
)
 
(274
)
 
23

 
 
 
 
 
 
Less: Maintenance and replacement capital expenditures, including accrual for reserve replacement (1)
(5,001
)
 
(3,026
)
 
(649
)
 
 
 
 
 
 
Add: Accretion of asset retirement obligation
246

 
228

 
102

 
 
 
 
 
 
Add: Unit based compensation
1,470

 

 

 
 
 
 
 
 
Distributable cash flow
135,093

 
67,339

 
18,129

 
 
 
 
 
 
Adjusted for: Distributable cash flow attributable to Hi-Crush Augusta LLC, net of intercompany eliminations, prior to the Augusta Contribution (2)
(7,199
)
 
696

 
832

 
 
 
 
 
 
Distributable cash flow attributable to Hi-Crush Partners LP
127,894

 
68,035

 
18,961

 
 
 
 
 
 
Less: Distributable cash flow attributable to holders of incentive distribution rights
(18,401
)
 

 

 
 
 
 
 
 
Distributable cash flow attributable to common and subordinated unitholders
$
109,493

 
$
68,035

 
$
18,961

 
 
 
 
 
 
(1) 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.
(2) The Partnership's historical financial information has been recast to consolidate Augusta for all periods presented. For purposes of calculating distributable cash flow attributable to Hi-Crush Partners LP, the Partnership excludes the incremental amount of recasted distributable cash flow earned during the periods prior to the Augusta Contribution.

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
You should read the following discussion of our historical performance and financial condition together with Part II, Item 6, “Selected Financial Data,” the description of the business appearing in Part 1, Item 1, “Business,” and the consolidated financial statements and the related notes in Part II, Item 8 of this Annual Report on Form 10-K. This discussion contains forward-looking statements that are based on the views and beliefs of our management, as well as assumptions and estimates made by our management. Actual results could differ materially from such forward-looking statements as a result of various risk factors, including those that may not be in the control of management. Factors that could cause or contribute to these differences include those discussed below and elsewhere in this report, particularly in Item 1A, “Risk Factors” and under “Forward-Looking Statements.” All amounts are presented in thousands except acreage, tonnage and per unit data, or where otherwise noted.

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Overview
We are a pure play, low-cost, domestic producer and supplier of premium 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 consist of “Northern White” sand, a resource existing predominately in Wisconsin and limited portions of the upper Midwest region of the United States, which is highly valued as a preferred proppant because it exceeds all API specifications. We own, operate and develop sand reserves and related excavation and processing facilities and will seek to acquire or develop additional facilities. Our 751-acre facility with integrated rail infrastructure located in Wyeville, Wisconsin (the “Wyeville facility”) enables us to process and cost-effectively deliver approximately 1,600,000 tons of 20/70 frac sand per year. We also own a 98.0% interest in Hi-Crush Augusta LLC (“Augusta”), which owns a 1,187-acre facility with integrated rail infrastructure located in Eau Claire County, Wisconsin (the “Augusta facility”), which enables us to process and cost-effectively deliver approximately 2,600,000 tons of 20/70 frac sand per year. We purchase sand from our sponsor's production facility near Whitehall, Wisconsin (the "Whitehall facility"), a 1,447-acre facility. A substantial portion of our and our sponsor's frac sand production is sold to leading pressure pumping service providers under long-term contracts that require our customers to pay a specified price for a specified volume of frac sand each month.
On January 31, 2013, we entered into an agreement with our sponsor to acquire a preferred interest in Hi-Crush Augusta LLC, the entity that owned our sponsor’s Augusta facility, for $37,500 in cash and 3,750,000 Class B Units in the Partnership. Our sponsor did not receive distributions on the Class B units until they converted into common units. The conditions precedent to conversion of the Class B units were satisfied upon payment of our distribution on August 15, 2014 and, our sponsor, who was 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. The preferred interest in Augusta entitled us to a preferred distribution of $3,750 per quarter, or $15,000 annually.
On April 8, 2014, the Partnership entered into a contribution agreement with our sponsor to acquire substantially all of the remaining equity interests in our sponsor’s Augusta facility for cash consideration of $224,250 (the “Augusta Contribution”). To finance the Augusta Contribution and refinance the Partnership’s revolving credit facility, (i) on April 8, 2014, the Partnership commenced a primary public offering of 4,250,000 common units representing limited partnership interests in the Partnership and (ii) on April 28, 2014, the Partnership entered into a $200,000 senior secured term loan facility with certain lenders. The Partnership’s primary public offering closed on April 15, 2014. On May 9, 2014, the Partnership issued an additional 75,000 common units pursuant to the partial exercise of the underwriters' over-allotment option in connection with the April 2014 primary public offering. Net proceeds to the Partnership from the primary offering and the exercise of the over allotment option totaled $170,693. Upon receipt of the proceeds from the public offering on April 15, 2014, the Partnership paid off the outstanding balance of $124,750 under its revolving credit facility. The Augusta Contribution closed on April 28, 2014, and at closing, the Partnership’s preferred equity interest in Augusta was converted into common equity interests of Augusta. Following the Augusta Contribution, the Partnership owns 98.0% of Augusta’s common equity interests. In addition, on April 28, 2014, the Partnership entered into a $150,000 senior secured revolving credit facility with various financial institutions by amending and restating its prior $200,000 revolving credit facility.
Our June 10, 2013 acquisition of D & I Silica, LLC (“D&I”) transformed us into an integrated Northern White frac sand producer, transporter, marketer and distributor. D&I is the largest independent frac sand supplier to the oil and gas industry drilling in the Marcellus and Utica shales. D&I operates through an extensive logistics network of rail-served origin and destination terminals located in the Midwest near supply sources and strategically throughout Pennsylvania, Ohio, New York and Texas.
In connection with our initial public offering ("IPO") and our sponsor's contribution of the Wyeville facility and operations, we entered into the following agreements:
Services Agreement: Effective August 16, 2012, we entered into a services agreement (the “Services Agreement”) with Hi-Crush Services LLC (“Hi-Crush Services”), pursuant to which Hi-Crush Services provides certain management and administrative services to our general partner in connection with operating our business. Under this agreement, we reimburse Hi-Crush Services, on a monthly basis, for the allocable expenses that it incurs in its performance of the specified services. These expenses include, among other things, salary, bonus, incentive compensation, rent and other administrative expenses for individuals and entities that perform services for us or on our behalf.






55


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

56


Basis of Presentation
The following discussion of our historical performance and financial condition is derived from the historical financial statements of our sponsor, Hi-Crush Proppants LLC, which is our accounting predecessor for financial reporting purposes through August 15, 2012. On August 16, 2012, our sponsor contributed some but not all of its assets and liabilities to us in connection with our initial public offering. Accordingly, the historical financial results through August 15, 2012 discussed below include capital expenditures and other costs related to assets that were not contributed to us in connection with our initial public offering as well as long-term debt and related expenses that were retained by our sponsor following the completion of our initial public offering. The consolidated financial statements include results of operations and cash flows for D&I prospectively from June 11, 2013.
Factors Impacting Comparability of Our Financial Results
Our historical results of operations and cash flows, are not indicative of results of operations and cash flows to be expected in the future, principally for the following reasons:
We completed our acquisition of D&I in June 2013. On June 10, 2013, we acquired D&I, an independent frac sand supplier, transforming us into an integrated Northern White frac sand producer, transporter, marketer and distributor. As a result of the acquisition, we now operate through an extensive logistics network of rail-served origin and destination terminals. Subsequent to June 10, 2013, we incur freight and logistics costs involved in the sourcing of sand to the destination terminals, as well as purchase sand from other suppliers.
Our Wyeville facility did not generate sales until we commenced operations in July 2011. Our first shipment of frac sand to a customer from our Wyeville facility occurred on July 21, 2011. Accordingly, our financial statements for the year ended December 31, 2011 reflect operations only from July 21, 2011 through the end of the year.
Our Augusta facility did not generate sales until we commenced operations in July 2012. Our first shipment of frac sand to a customer from our Augusta facility occurred on July 31, 2012. Accordingly, our financial statements for the period ended December 31, 2012 reflect operations only from July 31, 2012 through the end of the year.
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. Accordingly, our financial statements for the year ended December 31, 2014 reflect volume purchases from the Whitehall facility only from September 2014 through the end of 2014.
We completed an expansion of our Wyeville facility in March 2012. In March 2012, we completed an expansion of our Wyeville facility that increased rated processing capacity from 950,000 to approximately 1,600,000 tons per year.
We constructed additional equipment and silo storage facilities to produce and ship 100 mesh product. During the third quarter of 2013, we began selling 100 mesh product to customers. During 2014, we completed construction of additional equipment and silo storage facilities to store 100 mesh product at our production facilities. Sales prices for 100 mesh are typically lower than prices of other grades of sand.
We completed an expansion of our Augusta facility. During the fourth quarter of 2014, we completed an expansion of our Augusta facility that increased rated processing capacity from 1,600,000 to approximately 2,600,000 tons per year.
Our historical financial results include certain costs incurred by entities which were not contributed to us by our sponsor in connection with our IPO. For the year ended December 31, 2011 and the period from January 1, 2012 through August 15, 2012, our sponsor incurred operating expenses, consisting of general and administrative expenses and exploration costs, in connection with these retained operations of $1.0 million and $2.3 million, respectively.
Our historical financial results include long-term debt and related expenses that were not contributed to us by our sponsor in connection with the IPO. Our sponsor had indebtedness outstanding under various subordinated promissory notes and a senior secured revolving credit facility, all of which were retained by our sponsor following the completion of the IPO. For the year ended December 31, 2011 and the period from January 1, 2012 through August 15, 2012, our sponsor incurred interest expense related to the subordinated promissory notes and senior secured credit facility of $1.9 million and $3.8 million, respectively. We did not have any indebtedness outstanding as of the closing of the IPO.
We terminated certain royalty agreements in July 2012, which resulted in a reduction in our royalty costs. Effective July 2012, we terminated certain royalty agreements for a one-time cash payment of $14.0 million. The termination of these royalty agreements resulted in a reduction in our ongoing royalty costs from $6.15 per ton of sand excavated, delivered and paid for to $2.50 per ton of sand excavated, delivered and paid for at our Wyeville facility. If we produce and sell 1,600,000 tons of frac sand annually, we would expect the reduction in our royalty costs due to the termination of these agreements will be $5.8 million per year.





57


We currently incur additional general and administrative expenses as a publicly traded partnership. We have incurred incremental expenses as a publicly traded entity since our IPO. These expenses are associated with compliance under the Exchange Act, annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, investor relations, registrar and transfer agent fees, audit fees, incremental director and officer liability insurance costs and director and officer compensation. These incremental expenses exclude the costs incurred by our sponsor during the IPO process, as well as the costs associated with the initial implementation of our Sarbanes-Oxley Section 404 internal control reviews and testing.
We are incurring additional general and administrative expenses as a result of our expansion and acquisitions. We are incurring additional general and administrative expenses to support our recent expansion, including management level positions in sales, operations, human resources, legal, accounting and reporting, as well as license fees associated with upgraded accounting and reporting software. We expect these incremental growth associated expenses to gradually increase over time as we hire additional personnel.
We are incurring increased interest expense on our credit facility as a result of our acquisition of D&I and the Augusta Contribution. As of January 1, 2013, we did not have any indebtedness outstanding. In January 2013, in connection with our acquisition of a preferred interest in Augusta, we drew $38,250 under our credit facility. In June 2013, in connection with our acquisition of D&I, we drew $100,000 under our credit facility. In March 2014, we repaid $13,500 under our credit facility. The remaining outstanding balance of the credit facility was repaid in full on April 15, 2014 with the proceeds from a public offering of our common units. On April 28, 2014, the Partnership entered into a senior secured term loan credit facility that permits aggregate borrowings of up to $200,000, which was fully drawn down on April 28, 2014. The outstanding balance of $196,688 carries an interest rate of 4.75% as of December 31, 2014.
We incurred legal and advisory expenses in connection with our unitholder lawsuits. We incurred legal and advisory expenses in connection with our termination of the Baker Hughes supply agreement and related lawsuit, which settled on October 18, 2013, and the resulting unit holder lawsuits, which settlement was approved by the court on January 5, 2015.
Unless otherwise indicated, references in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” to “Hi-Crush Partners LP,” “we,” “our,” “us” or like terms when used in a historical context through August 15, 2012 refer to the business and results of operations of Hi-Crush Proppants LLC, our sponsor and accounting predecessor. Otherwise, those terms refer to Hi-Crush Partners LP and its subsidiaries following its initial public offering and formation transaction on August 16, 2012, as described in the “Overview” section.
Our Assets and Operations
We own and operate the Wyeville facility, which is located in Monroe County, Wisconsin and, as of December 31, 2014, contained 75.5 million tons of proven recoverable saleable sand reserves. We also own a 98.0% interest in the Augusta facility, which is located in Eau Claire County, Wisconsin and, as of December 31, 2014, contained 45.0 million tons of proven sand reserves. According to John T. Boyd Company ("John T. Boyd"), our proven reserves at the Wyeville and Augusta facilities consist of coarse grade Northern White sand exceeding API specifications. Analysis of our sand at the Wyeville and Augusta facilities by independent third-party testing companies indicates that they demonstrate characteristics exceeding of API specifications with regard to crush strength, turbidity and roundness and sphericity.
We acquired the Wyeville acreage and commenced construction of the Wyeville facility in January 2011. We completed construction of the Wyeville facility and commenced sand excavation and processing in June 2011 with an initial plant processing capacity of 950,000 tons per year, and customer shipments were initiated in July 2011. We completed an expansion in March 2012 that increased our annual processing rated capacity to approximately 1,600,000 tons per year. The additional expansion to allow us to produce 100 mesh sand at our Wyeville facility was completed in 2013, which increased our annual processing capacity for all grades of sand to approximately 1,850,000 tons per year.
We acquired the Augusta acreage and commenced construction of the Augusta facility in March 2012. We completed construction of the Augusta facility and commenced sand excavation and processing in June 2012 with an initial plant processing capacity of 1,600,000 tons of 20/70 frac sand per year, and customer shipments were initiated in July 2012. We completed an expansion in the fourth quarter of 2014 that increased our annual processing rated capacity to approximately 2,600,000 tons of 20/70 frac sand per year.
During the third quarter of 2013, we began selling 100 mesh product to customers. During 2014, we completed construction of additional equipment and silo storage facilities to store 100 mesh product at our facilities. During the third quarter of 2014, our sponsor completed construction of the 1,447-acre Whitehall facility with integrated rail infrastructure. As of December 31, 2014, this facility contained 78.9 million tons of proven, recoverable salable sand reserves and is capable of delivering approximately 2,600,000 tons of 20/70 frac sand per year.

58


As of February 27, 2015, we had contracted to sell 6.6 million tons in 2015 from our production facilities and destination terminals, including sand to be purchased from our sponsor's Whitehall facility. Based on third-party reserve reports by John T. Boyd, we have an implied average reserve life of 27 years, assuming production at the rated capacity of 4,450,000 tons per year.
As of December 31, 2014, we operated 14 destination rail-based terminal locations throughout the Marcellus and Utica shales and the Permian basin. Our destination terminals include approximately 325,300 tons of rail storage capacity and we are currently in the process of expanding our silo storage capacity in the Marcellus and Utica and other shale basins by more than 70,000 tons, which will result in over 100,000 tons of silo storage capacity. Our Minerva, Mingo Junction, Pittston, Smithfield and Wellsboro terminals are capable of accommodating unit trains.
We are continuously looking to increase the number of destination 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 destination 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. We also have the ability to connect to short-line railroads as necessary to meet our customers’ evolving in-basin product needs. As of December 31, 2014, we leased or owned 2,721 railcars used to transport our sand from origin to destination and manage a fleet of approximately 4,500 additional railcars dedicated to our facilities by our customers or the Class I railroads.


59


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 our customers under long-term contracts that require our customers to pay a specified price for a specified annual volume of sand, which contracts have current terms expiring between 2016 and 2019. 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, the price per ton and liquidated damages in the event either we or the customer fails to meet minimum requirements. Prices in our current contracts are fixed for the entire term of the contracts with certain volumes being subject to annual fixed price escalators. As a result, our revenue during the duration of these contracts may not follow broader industry pricing trends.
Delivery of sand to our customers may occur at the rail origin or at the destination terminal. 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. In addition to our frac sand and service revenues, we lease silo space to customers under long-term lease agreements, which typically require monthly payments over the term of the lease.
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.




60


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 facility, 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, direct and indirect labor, utilities and maintenance costs are capitalized as a component of inventory and are reflected in cost of goods sold when inventory is sold.
We pay royalties to third parties at our facilities at various rates, as defined in the individual royalty agreements, at an aggregate rate of approximately $2.50 to $6.15 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, terminal switch fees, demurrage costs, storage fees, labor and rent.
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 a diverse base of railroads to transport our sand and transportation costs are typically negotiated through long-term working relationships.
In addition to our sand and transportation costs, we incur other costs, some of which are passed through to our customers. For example, we incur terminal switch fees payable to the railroads when they transport to certain of our locations along with demurrage and storage fees. We also pay demurrage and storage fees when we utilize system railcars as additional storage capacity at our terminals. Other key components involved in transporting and offloading our sand shipments include on-site labor and railcar rental fees.
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.



61


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, production costs, earnings before interest, taxes, depreciation and amortization (“EBITDA”), and distributable cash flow.
Gross Profit and Production Costs
Price per ton excavated is fixed, and royalties are generally fixed based on tons excavated, delivered and paid for. Considering this largely fixed cost base, our production costs will largely be affected by our ability to control other direct and indirect costs associated with processing frac sand. We use production costs, which we define as costs of goods sold at our production facilities excluding depreciation and depletion, to measure our financial performance. We believe production costs is a meaningful measure because it provides a measure of operating performance that is unaffected by historical cost basis.
Gross profit is further impacted by our ability to control other direct and indirect costs associated with the transportation and delivery of frac sand to our customers. 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.
As a result, production volumes, costs of goods sold per ton, production costs per ton, sales volumes, sales price per ton sold and gross profit are key metrics used by management to evaluate our results of operations.
EBITDA and Distributable Cash Flow
We view EBITDA as an important indicator of performance. We define EBITDA as net income plus depreciation, depletion and amortization and interest expense, net of interest income. We use distributable cash flow to evaluate whether we are generating sufficient cash flow to support distributions to our unitholders. We define distributable cash flow as 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. Distributable cash flow will not reflect changes in working capital balances. EBITDA is a supplemental measure utilized by our management and other users of our financial statements such as investors, commercial banks, research analysts and others, to assess the financial performance of our assets without regard to financing methods, capital structure or historical cost basis. Distributable cash flow is a supplemental measure used to measure the ability of our assets to generate cash sufficient to support our indebtedness and make cash distributions to our unitholders.
Note Regarding Non-GAAP Financial Measures
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 or distributable cash flow in isolation or as substitutes for analysis of our results as reported under GAAP. Because 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 “Selected Financial Data—Non-GAAP Financial Measures.”

62


Results of Operations
The following discussion of our historical performance and financial condition is derived from the Partnership’s historical financial statements and those of our sponsor, Hi-Crush Proppants LLC, which was our accounting predecessor for financial reporting purposes through August 15, 2012. On August 16, 2012, our sponsor contributed some but not all of its assets and liabilities to us in connection with our IPO. Accordingly, the historical financial results through August 15, 2012 discussed below include capital expenditures and other costs related to assets that were not contributed to us in connection with our IPO as well as long-term debt and related expenses that were retained by our sponsor following the completion of our IPO.
The Augusta Contribution was accounted for as a transaction between entities under common control whereby Augusta's net assets were recorded at their historical cost. Therefore, the Partnership's historical financial information was recast to combine Augusta and the Partnership as if the combination had been in effect since inception of the common control.
The discussion of our historical performance and financial condition is presented for the Successor years ended December 31, 2014 and 2013, the Successor period from August 16, 2012 through December 31, 2012 and the Predecessor periods from January 1, 2012 through August 15, 2012. The results of operations for the year ended December 31, 2012 are also presented on a pro forma basis. The results of operations for the Predecessor periods are for our sponsor. We believe that the discussion on pro forma basis is a useful supplement to the historical results as it allows the Predecessor and Successor operating results for the period ended December 31, 2012 to be analyzed on a more comparable basis to the Successor results for the years ended December 31, 2014 and 2013. The unaudited pro forma combined consolidated statements of operations reflect the consolidated results of operations of the Partnership as if our IPO had occurred on January 1, 2012. The historical information has been adjusted to give effect to events and circumstances that are (i) directly attributed to our IPO, (ii) factually supportable and (iii), with respect to the statement of operations, expected to have a continuing impact on the combined results. Such items include the elimination of interest expense related to outstanding debt held by our sponsor prior to our IPO as well as the operating results of entities retained by our sponsor. This unaudited pro forma information should not be relied upon as necessarily being indicative of the results that may be obtained in the future.
The following table presents consolidated revenues and expenses for the periods indicated. This information is derived from the consolidated statements of operations for the Successor years ended December 31, 2014 and 2013, the Successor period from August 16, 2012 through December 31, 2012 and the Predecessor periods from January 1, 2012 through August 15, 2012. The year ended December 31, 2012 is also presented on a pro forma basis, as described above.
 
 
 
 
 
As Reported
 
 
 
 
 
 
 
 
 
Period from
 
Period from
 
 
 
Pro Forma
 
 
 
 
 
August 16
 
January 1
 
 
 
for the
 
Year Ended
 
Year Ended
 
through
 
through
 
Pro Forma
 
Year Ended
 
December 31,
 
December 31,
 
December 31,
 
August 15,
 
Adjustments
 
December 31,
 
2014
 
2013
 
2012
 
2012
 
(a)
 
2012
 
Successor
 
Successor
 
Successor
 
Predecessor
 
 
 
 
Revenues
$
386,547

 
$
178,970

 
$
31,770

 
$
46,776

 
$

 
$
78,546

Costs of goods sold
 
 
 
 
 
 
 
 
 
 
 
Production costs
58,452

 
41,999

 
8,944

 
12,247

 

 
21,191

Other cost of sales
156,904

 
46,688

 

 

 

 

Depreciation, depletion and amortization
10,628

 
7,197

 
1,109

 
1,089

 

 
2,198

Gross profit
160,563

 
83,086

 
21,717

 
33,440

 

 
55,157

Operating costs and expenses
26,592

 
19,371

 
3,980

 
5,186

 
(2,348
)
 
6,818

Income from operations
133,971

 
63,715

 
17,737

 
28,254

 
2,348

 
48,339

Other income (expense)
 
 
 
 
 
 
 
 
 
 
 
Other income

 

 

 
6

 

 
6

Interest expense
(9,946
)
 
(3,671
)
 
(320
)
 
(3,240
)
 
3,240

 
(320
)
Net income
124,025

 
60,044

 
17,417

 
25,020

 
5,588

 
48,025

(Income) loss attributable to non-controlling interest
(955
)
 
(274
)
 
23

 

 

 
23

Net income attributable to Hi-Crush Partners LP
$
123,070

 
$
59,770

 
$
17,440

 
$
25,020

 
$
5,588

 
$
48,048

(a) Pro forma adjustments exclude operating results relative to entities retained by our sponsor and interest expense incurred under our sponsor's credit facility through August 15, 2012.




63


Year Ended December 31, 2014 Compared to Year Ended December 31, 2013
Revenues
Revenues generated from the sale of frac sand were $323,043 for the year ended December 31, 2014, during which we sold 4,584,811 tons of frac sand. Revenue was $165,413 for the year ended December 31, 2013, during which we sold 2,520,119 tons of frac sand. Average sales price was $70 and $66 for the years ended December 31, 2014 and 2013, respectively. The increase in sales price is due to the mix in pricing of FOB plant and FOB destination (67% and 79% of tons were sold FOB plant for the years ended December 31, 2014 and 2013, respectively) in addition to price increases in our contracts and spot sales reflecting improving market conditions in 2014.
Other revenue related to transload, terminaling, silo leases and other services was $63,504 and $13,557 for the years ended December 31, 2014 and 2013, respectively. Other revenue increased primarily as a result of inclusion of destination terminal operations for a full year in 2014 compared to slightly more than 6 months in 2013. Other services revenues also increased as customers who purchased sand at the rail origin utilized our logistics capabilities for transportation of the sand to the ultimate destination.
Costs of goods sold – Production costs
We incurred production costs of $58,452, or $15.78 per ton produced and delivered, for the year ended December 31, 2014, compared to $41,999, or $18.74 per ton produced and delivered, for the year ended December 31, 2013.
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, 2014 and 2013.
 
Year Ended
 
Year Ended
 
December 31,
 
December 31,
 
2014
 
2013
Excavation costs
$
16,122

 
$
12,526

Plant operating costs
27,747

 
21,144

Royalties
14,583

 
8,329

   Total production costs
$
58,452

 
$
41,999

The overall increase in production costs was attributable to higher tonnage produced and delivered from our production facilities during the year ended December 31, 2014 as compared to the year ended December 31, 2013, partially offset by reduced per ton costs due to operating efficiencies and reduced volumes of rejected material. Both factors are attributable, in part, to the increased production and sale of 100 mesh sand during the year ended December 31, 2014 compared to the prior year.
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, terminal switch fees, demurrage costs, storage fees, labor and 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 demurrage costs, storage fees, labor and rent are charged to costs of goods sold in the period in which they are incurred.
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 through the spot market. For the years ended December 31, 2014 and 2013, we incurred $36,253 and $9,975 of purchased sand costs, respectively. The increase in purchases of sand is primarily attributable to the start up of our sponsor's Whitehall operations in the third quarter of 2014. In addition, during the year ended December 31, 2013, we incurred $1,171 of non-cash costs associated with the sale of inventory marked up to fair value in connection with the D&I acquisition.
We incur transportation costs including trucking, freight charges and fuel surcharges when transporting our sand from its origin to destination. For the years ended December 31, 2014 and 2013, we incurred $104,919 and $25,292 of transportation costs, respectively. Other costs of sales was $15,732 and $10,250 during the years ended December 31, 2014 and 2013, respectively, and was primarily comprised of demurrage, storage fees and on-site labor. The increase in transportation and other costs of sales was driven by increased throughput of tonnage at our destination terminals.
Costs of goods sold – Depreciation, depletion and amortization of intangible assets
For the years ended December 31, 2014 and 2013, we incurred $10,628 and $7,197, respectively, of depreciation, depletion and amortization expense.
Gross Profit
Gross profit was $160,563 and $83,086 for the years ended December 31, 2014 and 2013, respectively. Gross profit was primarily impacted by additional tons sold and reduced production per ton produced and delivered.


64


Operating Costs and Expenses
For the years ended December 31, 2014 and 2013, we incurred general and administrative expenses of $26,346 and $19,096, respectively. The increase in such costs was attributable to increased amortization of intangible assets of $793, unit based compensation of $1,470, and higher payroll and related costs from additional sponsor headcount. This increase was offset by lower transaction costs, as we incurred $768 in 2014 related to the Augusta Contribution, as compared to the $2,179 of costs incurred in 2013 related to our acquisition of D&I and our preferred interest in Augusta and $1,143 of legal and advisory costs..
Interest Expense
Interest expense was $9,946 and $3,671 for the years ended December 31, 2014 and 2013, respectively. The increase in interest expense during 2014 was primarily attributable to interest on our new $200,000 senior secured term loan facility, which was fully drawn on April 28, 2014 to finance the Augusta Contribution.
Net Income Attributable to Hi-Crush Partners LP
Net income attributable to Hi-Crush Partners LP was $123,070 and $59,770 for the years ended December 31, 2014 and 2013, respectively.
Successor - Year Ended December 31, 2013
Revenues
Revenues include $165,413 generated from the sale of frac sand. For the year ended December 31, 2013, we sold 2,520,119 tons of frac sand.
Other revenue was $13,557 for the year ended December 31, 2013 related to transload and terminaling, silo leases and other services.
Costs of goods sold – Production costs
We incurred production costs of $41,999 to produce and deliver 2,241,199 tons of frac sand at our production facilities, or $18.74 per ton produced and delivered, for the year ended December 31, 2013.
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 listing of the drivers impacting the level of production costs for the year ended December 31, 2013.
 
Year Ended
 
December 31,
 
2013
Excavation costs
$
12,526

Plant operating costs
21,144

Royalties
8,329

   Total production costs
$
41,999

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, terminal switch fees, demurrage costs, storage fees, labor and rent. The cost of purchased sand and transportation related charges are capitalized as a component of inventory and are reflected in costs of goods sold when inventory is sold. Other cost components, including demurrage costs, storage fees, labor and rent, are charged to costs of goods sold in the period in which they are incurred.
We purchase sand through long-term supply agreements with third parties at a fixed price per ton, and through the spot market. For the year ended December 31, 2013, we incurred $9,975 of purchased sand costs. In addition, we incurred $1,171 of non-cash costs associated with the sale of inventory marked up to fair value in connection with the D&I acquisition.
We incur transportation costs including trucking, freight charges and fuel surcharges when transporting our sand from its origin to destination. For the year ended December 31, 2013, we incurred $25,292 of transportation costs.
Other costs of sales was $10,250 during the year ended December 31, 2013, and was primarily comprised of demurrage, storage fees, on-site labor and railcar rental fees.
Costs of goods sold – Depreciation, depletion and amortization of intangible assets
For the year ended December 31, 2013, we incurred $7,197 of depreciation, depletion and amortization expense.
Gross Profit
Gross profit was $83,086 for the year ended December 31, 2013.

65


Operating Costs and Expenses
The principal components of our operating costs and expenses are general and administrative expenses, which totaled $19,096 for the year ended December 31, 2013. General and administrative expenses include costs directly incurred by the Partnership as well as those charged by Hi-Crush Services LLC ("Hi-Crush Services"), a subsidiary of our sponsor, under the Services Agreement for salaries, bonus incentive compensation, rent and other administrative expenses. General and administrative expenses also include the amortization expense attributable to intangible assets acquired through the D&I acquisition, which totaled $2,620 during 2013.
During 2013, we incurred legal and advisory expenses in connection with our termination of the Baker Hughes supply agreement and the resulting unit holder lawsuits of $643 and $500, respectively. As a result of our acquisition of D&I and our preferred interest in Augusta, we incurred transaction costs of $1,728 and $451, respectively. Such legal, advisory and transaction costs are reflected as general and administrative expenses.
Interest Expense
Interest expense was $3,671 for the year ended December 31, 2013 and is comprised of commitment fees and interest expense on borrowings under our four-year $200,000 revolving credit facility, coupled with the amortization of associated loan origination costs.
Net Income Attributable to Hi-Crush Partners LP
Net income attributable to Hi-Crush Partners LP was $59,770 for the year ended December 31, 2013.
Successor - Period from August 16 to December 31, 2012
Revenue was $31,770 for the period from August 16 to December 31, 2012, during which we sold 481,208 tons of frac sand under four long-term contracts, one of which was terminated on November 12, 2012. Production costs were $8,944, or $18.59 per ton sold, and gross profit was $21,717. Net income was $17,417 for the period from August 16 to December 31, 2012.
Predecessor – Period from January 1 to August 15, 2012
Revenue was $46,776 for the period from January 1, 2012 to August 15, 2012, during which we sold 726,213 tons of frac sand under four long-term contracts, two of which commenced in May 2012. Production costs were $12,247, or $16.86 per ton sold, and gross profit was $33,440. Due to the nature of the long-term contracts with our customers that require our customers to pay a specified price for a specified volume of frac sand each month, gross profit is primarily affected by royalties and the cost to excavate and process sand. Production costs per ton were impacted by the reduced royalty rate per ton resulting from the July 2012 buyout of certain royalty agreements, as well as the full impact of enhanced production efficiencies derived from the Wyeville plant expansion, completed in March 2012. General and administrative expenses were $4,631, including certain expenses incurred by our sponsor, such as legal and professional fees and payroll and related costs associated with the preparation for, and in connection with, our initial public offering. Interest expense was $3,240 related to our sponsor’s debt, all of which was retained by our sponsor following the initial public offering. Net income was $25,020 for the period from January 1, 2012 to August 15, 2012.
Supplemental Analysis - Successor Year Ended December 31, 2013 Compared to Pro Forma Year Ended December 31, 2012
Revenues
Revenues generated from the sale of frac sand were $165,413 for the year ended December 31, 2013, during which we sold 2,520,119 tons of frac sand. Revenue was $78,546 for the pro forma year ended December 31, 2012, during which we sold 1,207,421 tons of frac sand produced from our production facilities. Average sales price per ton was $66 for the year ended December 31, 2013 and $65 for the pro forma year ended December 31, 2012. The change in sales price between the two periods is due to the mix in pricing of FOB plant and FOB destination (79% and 100% of tons were sold FOB plant for the year ended December 31, 2013 and the pro forma year ended December 31, 2012, respectively) and the mix of product sold, partially offset by the reduced sales prices under one of our customer contracts.
Other revenue was $13,557 for the year ended December 31, 2013 related to transload and terminaling, silo leases and other services not provided by us prior to the acquisition of D&I in June 2013.











66


Costs of goods sold – Production costs
We incurred production costs of $41,999, or $18.74 per ton produced and delivered, for the year ended December 31, 2013, compared to $21,191, or $17.55 per ton sold, for the pro forma year ended December 31, 2012.
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 year ended December 31, 2013 and the pro forma year ended December 31, 2012.
 
 
 
Pro Forma
 
Year Ended
 
Year Ended
 
December 31,
 
December 31,
 
2013
 
2012
Excavation costs
$
12,526

 
$
4,908

Plant operating costs
21,144

 
11,285

Royalties
8,329

 
4,998

   Total production costs
$
41,999

 
$
21,191

The overall increase in production costs was attributable to higher tonnage produced and delivered from our Augusta facility during the year ended December 31, 2013 as compared to the pro forma year ended December 31, 2012. The Augusta facility generally has a higher production cost per ton compared to the Wyeville facility due to a higher royalty rate per ton and the operations of the conveyor system between the wet and dry plants. The higher 2013 production cost per ton was partially offset by the reduced royalty rate per ton resulting from our July 2012 buyout of certain royalty agreements.
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, terminal switch fees, demurrage costs, storage fees, labor and rent. The cost of purchased sand and transportation related charges are capitalized as a component of inventory and are reflected in costs of goods sold when inventory is sold. Other cost components, including demurrage costs, storage fees, labor and rent are charged to costs of goods sold in the period in which they are incurred. Other cost of sales were solely incurred subsequent to the D&I acquisition in June 2013. We did not incur other cost of sales during the pro forma year ended December 31, 2012.
We purchase sand through long-term supply agreements with third parties at a fixed price per ton and through the spot market. For the year ended December 31, 2013, we incurred $9,975 of purchased sand costs. In addition, we incurred $1,171 of non-cash costs associated with the sale of inventory marked up to fair value in connection with the D&I acquisition.
We incur transportation costs including trucking, freight charges and fuel surcharges when transporting our sand from its origin to destination. For the year ended December 31, 2013, we incurred $25,292 of transportation costs.
Other costs of sales was $10,250 during the year ended December 31, 2013, and was primarily comprised of demurrage, storage fees and on-site labor.
Costs of goods sold – Depreciation, depletion and amortization of intangible assets
For the year ended December 31, 2013 and the pro forma year ended Decembe