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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 December 31, 2012, we incurred $7,197 and $2,198, respectively, of depreciation, depletion and amortization expense. The increase in such costs is attributable to the acquisition of D&I and the depreciation and amortization of its tangible and intangible assets during the period.
Gross Profit
Gross profit was $83,086 for the year ended December 31, 2013 and $55,157 for the pro forma year ended December 31, 2012. The increase in gross profit was primarily the result of the D&I acquisition, additional tons sold, and reduced production costs per ton, offset by reduced average sales pricing resulting from the customer contract amendment effective April 1, 2013.








67


Operating Costs and Expenses
For the year ended December 31, 2013 and the pro forma year ended December 31, 2012, we incurred operating costs and expenses of $19,371 and $6,818, respectively. The principal components of our operating costs and expenses are general and administrative expenses. The increase in such costs was due to transaction costs of $2,179 associated with our acquisition of D&I and our preferred interest in Augusta, $2,620 of intangible asset amortization, $2,277 of costs attributable to the D&I operations, $1,143 of legal and advisory expenses in connection with our termination of the Baker Hughes supply agreement and the resulting unitholder lawsuits, and increased costs of $2,897 incurred in connection with the requirements of being a publicly traded partnership.
During the year ended December 31, 2013, legal fees included $500 in costs associated with unitholder litigation. Future legal expenses incurred in connection with the unit holder lawsuits beyond our $500 deductible, which was met during the second quarter of 2013, were reimbursable from our insurance carrier. Legal expenses associated with the Baker Hughes litigation were not reimbursable from our insurance carrier.
Interest Expense
Interest expense was $3,671 for the year ended December 31, 2013 compared to $320 in the pro forma year ended December 31, 2012. The interest expense for the 2012 pro forma period consisted of commitment fees and amortization of associated loan origination costs under the Partnership’s credit facility. The interest expense in the 2013 period related to 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 compared to net income of $48,048 for the pro forma year ended December 31, 2012.



68


Liquidity and Capital Resources
Overview
We expect our principal sources of liquidity will be cash generated by our operations, supplemented by borrowings under our amended and restated $150,000 five-year revolving credit facility, as necessary. We believe that cash from these sources will be sufficient to meet our short-term working capital requirements and long-term capital expenditure requirements. As of February 20, 2015, our sources of liquidity consisted of $13,444 of available cash and $118,848 pursuant to available borrowings under our revolving credit facility ($150,000, net of $25,000 of indebtedness and $6,152 letter of credit commitments). In addition, our general partner is authorized to issue an unlimited number of units without the approval of existing limited partner unitholders.
We expect that our future principal uses of cash will be for working capital, making distributions to our unitholders, capital expenditures and funding any debt service obligations. On January 15, 2015, our general partner’s board of directors declared a cash distribution for the fourth quarter of 2014 of $0.6750 per common and subordinated unit, or $2.70 on an annualized basis, and a distribution of $1,311 was declared for our holders of incentive distribution rights. This represented the tenth distribution declared by us and corresponds to a 42% increase from our minimum quarterly distribution of $0.4750 per unit. This distribution was paid on February 13, 2015, to unitholders of record on January 30, 2015. Based on the number of common and subordinated units outstanding as of February 27, 2015 and assuming we continue to pay a quarterly distribution of $0.6750 per common and subordinated unit per quarter, we would pay a distribution to our common and subordinated unitholders of approximately $24,947 per quarter, or $99,788 per year. If such distribution is paid, we intend to pay a quarterly distribution to our holders of incentive distribution rights of $1,311 per quarter, or $5,244 per year. We do not have a legal or contractual obligation to pay this distribution.
Working Capital
Working capital is the amount by which current assets exceed current liabilities and is a measure of our ability to pay our liabilities as they become due. As of December 31, 2014, we had a positive working capital balance of $59,297, as compared to $33,356 at December 31, 2013. The following table summarizes our working capital as of the dates indicated. 
 
December 31,
2014
 
December 31,
2013
Current assets:
 
 
 
Accounts receivable, net
$
82,117

 
$
37,442

Inventories
23,684

 
22,418

Prepaid expenses and other current assets
4,081

 
1,625

Total current assets
109,882

 
61,485

Current liabilities:
 
 
 
Accounts payable
24,878

 
10,108

Accrued and other current liabilities
12,248

 
7,669

Due to sponsor
13,459

 
10,352

Total current liabilities
50,585

 
28,129

Working capital
$
59,297

 
$
33,356

Accounts receivable increased by $44,675 during the year ended December 31, 2014, which was driven by higher sales volumes in the month of December 2014 compared to December 2013.
Our inventory consists primarily of sand that has been excavated and processed through the wet plant and finished goods in transit. The increase in our inventory of $1,266 was primarily driven by higher finished goods inventory of $1,856 during the period. Most of our finished goods inventory is either in transit to our customers or held at our terminals for future sale.
Prepaid expenses and other current assets increased by $2,456 during the year ended December 31, 2014. The increase was primarily driven by prepayments associated with our fleet of leased railcars.
Accounts payable and accrued liabilities increased by $19,349 on a combined basis during the year ended December 31, 2014. The increase was primarily attributable to the increase operating expenses due to higher sales volumes during the year ended December 31, 2014.
Our accounts payable to our sponsor increased $3,107 during the year ended December 31, 2014, primarily as a result of us purchasing sand from Hi-Crush Whitehall LLC.

69


Cash Flow Activities Were As Follows For 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
 
Pro Forma Adjustments (a)
 
Pro Forma for the Year Ended December 31, 2012
 
Successor
 
Successor
 
Successor
 
Predecessor
 
 
 
 
Net cash provided by (used in):
 
 
 
 
 
 
 
 
 
 
 
Operating activities
$
104,370

 
$
64,323

 
14,498

 
$
16,660

 
$

 
$
31,158

Investing activities
(264,715
)
 
(105,585
)
 
(8,218
)
 
(80,045
)
 

 
(88,263
)
Financing activities
144,383

 
51,372

 
2,234

 
61,048

 

 
63,282

(a) Pro forma adjustments give effect to exclude the cash flows attributable to entities retained by our sponsor through August 15, 2012.
Cash Flows - Successor Year Ended December 31, 2014 Compared to Successor Year Ended December 31, 2013
Operating Activities
Net cash provided by operating activities was $104,370 and $64,323 for the years ended December 31, 2014 and 2013, respectively. Operating cash flows include $124,025 and $60,044 of net income earned during the years ended December 31, 2014 and 2013, respectively, adjusted for non-cash operating expenses and changes in operating assets and liabilities described above. The increase in cash flows from operations was primarily attributable to additional cash flows generated from increased sales volumes.
Investing Activities
Net cash used in investing activities was $264,715 for the year ended December 31, 2014 and consisted of the $224,250 cost of the Augusta Contribution, capital expenditures primarily associated with the 1,000,000 ton expansion of processing capacity at our Augusta facility, purchases and construction of additional equipment and facilities to produce and store 100 mesh product at our production facilities, and construction costs for a new terminal facility in the Permian basin.
Net cash used in investing activities was $105,585 for the year ended December 31, 2013 and consisted primarily of cash payments of $94,955 paid for D&I and construction costs related to a new conveyor system installed over the rail line bisecting the Wyeville facility.
Financing Activities
Net cash provided by financing activities was $144,383 for the year ended December 31, 2014, and was comprised of $198,000 of cash proceeds from the term loan issuance and $170,693 from the issuance of 4,325,000 common units, offset by $77,421 of distributions to our unitholders, $7,120 of loan origination costs, a $138,250 repayment of our prior revolving credit facility and a $1,500 scheduled repayment of our term loan.
Net cash provided by financing activities was $51,372 for the year ended December 31, 2013, which included receipts of $138,250 of borrowings under our prior revolving credit facility and $5,615 of net repayments of affiliate financing from our sponsor. These inflows were offset by $58,414 of distributions, $829 of loan origination costs and a $33,250 repayment of long-term debt by Augusta.
Cash Flows - Successor Year Ended December 31, 2013
During the period, the Partnership generated $64,323 of cash flows from operations, $138,250 through receipts of borrowings under our credit facility and $5,615 of net repayments of affiliate financing from our sponsor. These funds were primarily used to pay $94,955 for the cash portion of the D&I acquisition price, $10,630 of capital expenditures, $58,414 of distributions, a $33,250 repayment of assumed debt from our sponsor, and $829 of loan origination costs during the period. Excess cash generated during the period of $10,110 was retained by the Partnership.
Cash Flows – Successor Period from August 16 through December 31, 2012
During the period, we generated $14,498 of cash flows from operations, received a $4,606 cash contribution from our sponsor and $4,250 of net affiliate financing from the sponsor. These funds were used to pay for $8,218 of investing activities, make $6,479 of distributions and pay $143 in loan origination costs. Excess cash generated during the period of $8,514 was retained by us.




70


Cash Flows – Predecessor Period from January 1 through August 15, 2012
During the period, the Predecessor generated $16,660 of cash flows from operations and $61,048 from financing activities. The financings included borrowings under our sponsor’s secured credit facility and the subordinated promissory notes. These funds, along with a portion of the beginning cash on hand, were used to pay for $80,075 of capital expenditures, which primarily related to the construction of the Augusta plant and expansion of the Wyeville plant.
Supplemental Analysis - Successor Year Ended December 31, 2013 Compared to Successor Pro Forma Year Ended December 31, 2012
Operating Activities
Net cash provided by operating activities was $64,323 for the year ended December 31, 2013 and $31,158 for the pro forma year ended December 31, 2012. Operating cash flows include $60,044 of net income earned during the year ended December 31, 2013 and $48,025 of net income earned in the pro forma year ended December 31, 2012, adjusted for non-cash operating expenses and changes in operating assets and liabilities.
Investing Activities
Net cash used in investing activities was $105,585 for the year ended December 31, 2013 and consisted primarily of $94,955 for the acquisition of D&I and $10,630 of capital expenditures, including the addition of 100 mesh production capabilities and a new conveyor system installed over the rail line bisecting the Wyeville property. Net cash used in investing activities was $88,263 for the pro forma year ended December 31, 2012 and consisted primarily of costs associated with the construction of the Augusta facility and the expansion of our Wyeville facility.
Financing Activities
Net cash provided by financing activities was $51,372 for the year ended December 31, 2013, which included receipts of $138,250 of borrowings under our credit facility and $5,615 of net repayments of affiliate financing from our sponsor. These inflows were offset by $58,414 of distributions, $33,250 repayment of assumed debt from our sponsor and payment of $829 of loan origination costs during the period.
Net cash proceeds from financing activities was $63,282 for the pro forma year ended December 31, 2012, which comprised $4,606 of contributions received from the sponsor and $66,985 of other financing proceeds, offset by $6,704 of distributions and payment of $1,605 of loan origination costs.
Off-Balance Sheet Arrangements
We do not have any off-balance sheet arrangements that have or are likely to have a material effect on our current or future financial condition, changes in financial condition, sales, expenses, results of operations, liquidity, capital expenditures or capital resources.
The Partnership has long-term operating leases for rail access, railcars and equipment at its terminal sites, which are also under long-term lease agreements with various railroads.
Capital Requirements
We plan to spend $30,000 to $50,000 in 2015 related to the expansion of our silo storage capacities at our Smithfield and Mingo Junction destination terminals and for capital improvements at our production facilities. There are no other significant anticipated capital requirements associated with our production facilities. We have no significant required capital commitments for new terminal facilities, although we may expand our footprint in existing or new shale basins with transload facilities.
Revolving Credit Facility and Senior Secured Term Loan Facility
As of February 20, 2015, we have a $150,000 senior secured revolving credit facility (our "revolving credit facility"), which matures in April 2019. This facility amended, restated and replaced our prior $200,000 four-year senior secured revolving credit facility. As of February 20, 2015, we had $25,000 of borrowings and $118,848 of undrawn borrowing capacity ($150,000, net of $25,000 of indebtedness and $6,152 letter of credit commitments) under our revolving credit facility. The revolving credit facility is available to fund working capital and for other 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.
As of February 20, 2015, we have a $200,000 senior secured term loan facility (our "senior secured term loan facility"), which matures in April 2021. As of February 20, 2015, the senior secured term loan facility was fully drawn. The senior secured term loan facility permits us to add one or more incremental term loan facilities in an aggregate amount not to exceed $100,000. Any incremental senior secured term loan facility would be on terms to be agreed among us, the administrative agent under the senior secured term loan facility and the lenders who agree to participate in the incremental facility. Borrowings under our senior secured term loan facility are secured by substantially all of our assets.


71


Subsidiary Guarantors
The Partnership has filed a registration statement on Form S-3 to register, among other securities, debt securities. Each of the subsidiaries of the Partnership as of March 31, 2014 (other than Hi-Crush Finance Corp., whose sole purpose is to act as a co-issuer of any debt securities) was a 100% directly or indirectly owned subsidiary of the Partnership (the “guarantors”), and will issue guarantees of the debt securities, if any of them issue guarantees, and such guarantees will be full and unconditional and will constitute the joint and several obligations of such guarantors. As of December 31, 2014, the guarantors were our sole subsidiaries, other than Hi-Crush Finance Corp., Hi-Crush Augusta Acquisition Co. LLC, Hi-Crush Canada Inc. and Hi-Crush Canada Distribution Corp., which are 100% owned subsidiaries, and Hi-Crush Augusta LLC, of which we own 98% of the common equity interests.
As of December 31, 2014, the Partnership had no assets or operations independent of its subsidiaries, and there were no significant restrictions upon the ability of the Partnership or any of its subsidiaries to obtain funds from its respective subsidiaries by dividend or loan. As of December 31, 2014, none of the assets of our subsidiaries represented restricted net assets pursuant to Rule 4-08(e)(3) of Regulation S-X under the Securities Act.



72


Customer Concentration
For the years ended December 31, 2014 and 2013, sales to each of Halliburton, Weatherford and FTS International accounted for greater than 10% of our total revenues. For the pro forma year ended December 31, 2012, sales to each of Halliburton, Weatherford, FTS International and Baker Hughes accounted for greater than 10% of our total revenues.

73


Contractual Obligations
The following table presents our contractual obligations and other commitments as of December 31, 2014:
 
Total
 
Less than 1 year
 
1-3 years
 
3-5 years
 
More than 5 years
Contractual Obligations
 
 
 
 
 
 
 
 
 
Asset retirement obligations (1)
$
6,730

 
$

 
$

 
$

 
$
6,730

Repayment of term loan
196,688

 
2,000

 
4,000

 
4,000

 
186,688

Repayment of other notes payable
3,676

 

 
3,676

 

 

Acquisition of mineral rights (2)
12,352

 
6,176

 
6,176

 

 

Operating lease obligations
80,388

 
16,893

 
31,734

 
26,378

 
5,383

Total
$
299,834

 
$
25,069

 
$
45,586

 
$
30,378

 
$
198,801

(1) The asset retirement obligation represents the fair value of the post closure reclamation and site restoration commitments for our property and processing facilities located in Augusta, Wisconsin and Wyeville, Wisconsin.
(2) On October 24, 2014, the Partnership entered into a purchase and sale agreement to acquire certain tracts of land and specific quantities of the underlying frac sand deposits. The transaction includes three separate tranches of land and deposits, to be acquired over a three-year period from 2014 through 2016. During 2014, the Partnership acquired the first tranche of land for $6,176. As of December 31, 2014, the Partnership has the commitment to purchase the remaining two tranches during 2015 and 2016 for total consideration of $12,352.

74


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

75


Recent Accounting Pronouncements
In August 2014, the Financial Accounting Standards Board ("FASB") issued ASU 2014-15, which provides guidance on determining when and how to disclose going-concern uncertainties in the financial statements. The new standard requires management to perform interim and annual assessments of an entity’s ability to continue as a going concern within one year of the date the financial statements are issued. An entity must provide certain disclosures if "conditions or events raise substantial doubt about the entity’s ability to continue as a going concern." The ASU applies to all entities and is effective for annual periods ending after December 15, 2016, and interim periods thereafter, with early adoption permitted. We are currently evaluating the future disclosure requirements under this guidance.
In June 2014, the FASB issued amended guidance on accounting for share-based payments when the terms of an award provide that a performance target could be achieved after the requisite service period. The amended guidance, which may be applied on a prospective or retrospective basis, will be effective for us beginning January 1, 2016. We anticipate that the adoption of this amended guidance will not materially affect our financial position, results of operations or cash flows.
In May 2014, the FASB issued an update that supersedes most current revenue recognition guidance, as well as some cost recognition guidance. The update requires that an entity recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This update also requires new qualitative and quantitative disclosures about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts, including significant judgments and changes in judgments, information about contract balances and performance obligations, and assets recognized from costs incurred to obtain or fulfill a contract. The authoritative guidance, which may be applied on a full retrospective or modified retrospective basis whereby the entity records a cumulative effect of initially applying this update at the date of initial application, will be effective for us beginning January 1, 2017. Early adoption is not permitted. We are currently evaluating the potential method and impact of this authoritative guidance on our consolidated financial statements.



76


Critical Accounting Policies and Estimates
The discussion and analysis of our financial condition and results of operations is based on our consolidated financial statements, which have been prepared in accordance with accounting principles generally acceptable in the United States of America. The preparation of these financial statements requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the dates of the financial statements and the reported revenues and expenses during the reporting periods. We evaluate these estimates and assumptions on an ongoing basis and base our estimates on historical experience, current conditions and various other assumptions that we believe to be reasonable under the circumstances. The results of these estimates form the basis for making judgments about the carrying values of assets and liabilities as well as identifying and assessing the accounting treatment with respect to commitments and contingencies. Our actual results may materially differ from these estimates.
Listed below are the accounting policies we believe are critical to our financial statements due to the degree of uncertainty regarding the estimates or assumptions involved, and that we believe are critical to the understanding of our operations.
Impairment of Long-lived Assets
Recoverability of investments in property, plant and equipment, and mineral rights is evaluated annually. Estimated future undiscounted net cash flows are calculated using estimates of proven and probable sand reserves, estimated future sales prices (considering historical and current prices, price trends and related factors) and operating costs and anticipated capital expenditures. Reductions in the carrying value of our investment are only recorded if the undiscounted cash flows are less than our book basis in the applicable assets.
Impairment losses are recognized based on the extent that the remaining investment exceeds the fair value, which is determined based upon the estimated future discounted net cash flows to be generated by the property, plant and equipment and mineral rights.
Management’s estimates of prices, recoverable proven and probable reserves and operating and capital costs are subject to certain risks and uncertainties which may affect the recoverability of our investments in property, plant and equipment. Although management has made its best estimate of these factors based on current conditions, it is reasonably possible that changes could occur in the near term, which could adversely affect management’s estimate of the net cash flows expected to be generated from its operating property. No impairment charges were recorded during 2014, 2013 or 2012.
Revenue Recognition
Frac sand sales revenues are recognized when legal title passes to the customer, which may occur at the production facility, rail origin or at the destination terminal. At that point, delivery has occurred, evidence of a contractual arrangement exists and collectability is reasonably assured. Amounts received from customers in advance of sand deliveries are recorded as deferred revenue. Revenue from make-whole provisions in our customer contracts is recognized at the end of the defined cure period.
A substantial portion of our frac sand is sold under long-term supply agreements, the current terms of which expire between 2016 and 2019. The agreements define, among other commitments, the volume of product that the Partnership must provide, the price that will be charged to the customer, and the volume that the customer must purchase at the end of the defined cure period, which can range from three months to the end of a contract year.
Transportation services revenues are recognized as the services have been completed, meaning the related services have been rendered. At that point, delivery of service has occurred, evidence of a contractual arrangement exists and collectability is reasonably assured. Amounts received from customers in advance of transportation services being rendered are recorded as deferred revenue.
Revenue attributable to silo storage leases is recorded on a straight-line basis over the term of the lease.
Asset Retirement Obligation
We estimate the future cost of dismantling, restoring and reclaiming operating excavation sites and related facilities in accordance with federal, state and local regulatory requirements. We record the initial estimated present value of reclamation costs as an asset retirement obligation and increase the carrying amount of the related asset by a corresponding amount. We allocate reclamation costs to expense over the life of the related assets and adjust the related liability for changes resulting from the passage of time and revisions to either the timing or amount of the original present value estimate. If the asset retirement obligation is settled for more or less than the carrying amount of the liability, a loss or gain will be recognized, respectively.





77


Inventories
Sand inventory is stated at the lower of cost or market using the average cost method.
Inventory manufactured at our production facilities includes direct excavation costs, processing costs, overhead allocation, depreciation and depletion. Stockpile tonnages are calculated by measuring the number of tons added and removed from the stockpile. Tonnages are verified periodically by an independent surveyor. Costs are calculated on a per ton basis and are applied to the stockpiles based on the number of tons in the stockpile.
Inventory transported for sale at our terminal facility includes the cost of purchased or manufactured sand, plus transportation related charges.
Spare parts inventory includes critical spares, materials and supplies. We account for spare parts on a first-in, first-out basis, and value the inventory at the lower of cost or market.
Depletion
We amortize the cost to acquire land and mineral rights using a units of production method, based on the total estimated reserves and tonnage extracted each period.
Goodwill and Intangible Assets
Goodwill represents the excess of purchase price over the fair value of net assets acquired. The Partnership performs an assessment of the recoverability of goodwill during the third quarter of each fiscal year, or more often if events or circumstances indicate the impairment of an asset may exist. Our assessment of goodwill is based on qualitative factors to determine whether the fair value of the reporting unit is more likely than not less than the carrying value. An additional quantitative impairment analysis is completed if the qualitative analysis indicates that the fair value is not substantially in excess of the carrying value. The quantitative analysis determines the fair value of the reporting unit based on the discounted cash flow method and relative market-based approaches. There were no impairment charges related to goodwill during the years ended December 31, 2014 and 2013.
We amortize the cost of other intangible assets on a straight line basis over their estimated useful lives, ranging from 1 to 20 years. An impairment assessment is performed if events or circumstances occur and may result in the change of the useful lives of the intangible assets. During the years ended December 31, 2014 and 2013, we did not record any impairment charges or changes in the useful life of intangible assets.
Fair Value of Financial Instruments
The amounts reported in the balance sheet as current assets or liabilities, including cash, accounts receivable, accounts payable, accrued and other current liabilities approximate fair value due to the short-term maturities of these instruments. The fair value of the senior secured term loan approximated $189,071 as of December 31, 2014, based on the market price quoted from external sources, compared with a carrying value of $198,500. If the senior secured term loan was measured at fair value in the financial statements, it would be classified as Level 2 in the fair value hierarchy.
Net Income per Limited Partner Unit
We have identified the sponsor’s incentive distribution rights as participating securities and compute income per unit using the two-class method under which any excess of distributions declared over net income shall be allocated to the partners based on their respective sharing of income specified in the partnership agreement. Net income per unit applicable to limited partners (including subordinated unitholders) is computed by dividing limited partners’ interest in net income, after deducting any sponsor incentive distributions, by the weighted-average number of outstanding common and subordinated units. Through March 31, 2014, basic and diluted net income per unit are the same as there were no potentially dilutive common or subordinated units outstanding.
Through August 15, 2014, the 3,750,000 Class B units outstanding did not have voting rights or rights to share in the Partnership’s periodic earnings, either through participation in its distributions or through an allocation of its undistributed earnings or losses, and so were not deemed to be participating securities in their form as Class B units. In addition, the conversion of the Class B units into common units was fully contingent upon the satisfaction of defined criteria pertaining to the cumulative payment of distributions and earnings per unit of the Partnership. Until all of the defined payment and earnings criteria were satisfied, the Class B units were not included in our calculation of either basic or diluted earnings per unit. As such, for the quarter ended June 30, 2014, the Class B units were included in our calculation of diluted earnings per unit. On August 15, 2014, the Class B units converted into common units, at which time income allocations commenced on such units and the common units were included in our calculation of basic and diluted earnings per unit.
The Partnership's historical financial information has been recast to consolidate Augusta for all periods presented. The amounts of incremental income or losses recasted to periods prior to the Augusta Contribution are excluded from the calculation of net income per limited partner unit.

78


Income Taxes
We and our sponsor are pass-through entities and are not considered taxing entities for federal tax purposes. Therefore, there is not a provision for income taxes in the accompanying condensed consolidated financial statements. Our net income or loss is allocated to our partners in accordance with the partnership agreement. The partners are taxed individually on their share of the Partnership’s earnings. At December 31, 2014 and 2013, we did not have any liabilities for uncertain tax positions or gross unrecognized tax benefit.

79


Related Party Transactions
On May 25, 2011, our sponsor entered into a management services agreement with Red Oak Capital Management LLC (the “Service Provider”) which is owned by two members who are also equity members in our sponsor. The agreement provides for certain management and administrative support services to be provided to our sponsor for a term of one year and that thereafter remains in place upon the same terms and conditions. Either party may terminate the agreement by delivering written notice within 90 days prior to the date of expiration of the initial term or any time after the expiration of the initial term, by delivering written notice 90 days prior to the desired date of termination. Our sponsor reimburses the Service Provider 95% of the Service Provider’s actual costs limited to $850 per year. Total fees were $166 during the period from August 16 through December 31, 2012 and $318 for the period from January 1 through August 15, 2012. These fees are included in general and administrative expenses. Management fees incurred during the years ended December 31, 2014 and 2013 are included as a portion of the management services expense from Hi-Crush Services, as discussed below.
The sponsor paid quarterly director fees to non-management directors that may be members and/or holders of the sponsor’s debt through the date of the IPO. Total fees were $62 for the period from January 1 through August 15, 2012.
During the years ended December 31, 2014 and 2013 and the period from August 16 through December 31, 2012, the Partnership incurred $9,421, $5,122 and $1,702, respectively, of management service expenses from Hi-Crush Services.
In the normal course of business, our sponsor and its affiliates, including Hi-Crush Services, and the Partnership may from time to time make payments on behalf of each other. During the period from August 16 through December 31, 2012, we made payments of $9,866 to various suppliers, vendors or other counterparties on behalf of our sponsor. This balance was offset by $1,028 of management fees charged by our sponsor and $3,223 of net payments made by our sponsor on behalf of us. The balance of $5,615 was repaid by our sponsor in February 2013.
During the year ended December 31, 2014, the Partnership purchased $23,705 of sand from Hi-Crush Whitehall LLC, a subsidiary of our sponsor and the entity that owns our sponsor's Whitehall facility, at a purchase price in excess of our production cost per ton.
During the year ended December 31, 2014, the Partnership purchased $1,385 of sand from Goose Landing, LLC, a wholly owned subsidiary of Northern Frac Proppants II, LLC. The father of Mr. Alston, who is our general partner's Chief Operating Officer, owns a controlling equity interest in Northern Frac Proppants II, LLC. Although we acquired the sand at a purchase price in excess of our production cost per ton, the terms of the purchase price were the result of arm's length negotiations.
As of December 31, 2014 and 2013, an outstanding balance of $13,459 and $10,352, respectively, payable to our sponsor is maintained as a current liability under the caption “Due to sponsor”. In connection with the acquisition of the preferred interest in Augusta, on January 31, 2013, our sponsor extinguished balances owed by Augusta as follows:
Conversion into common units of Hi-Crush Augusta LLC, representing a non-controlling interest in the Partnership
$
38,172

Conversion into preferred units of Hi-Crush Augusta LLC
9,543

Assumption of bank debt
33,250

Total payable to sponsor extinguished
$
80,965




80


ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
(Dollars in thousands)
Quantitative and Qualitative Disclosure of Market Risks
Market risk is the risk of loss arising from adverse changes in market rates and prices. Historically, our risks have been predominantly related to potential changes in the fair value of our long-term debt due to fluctuations in applicable market interest rates and those risks that arise in the normal course of business, as we do not engage in speculative, non-operating transactions, nor do we utilize financial instruments or derivative instruments for trading purposes.
The market for frac sand is indirectly exposed to fluctuations in the prices of crude oil and natural gas to the extent such fluctuations impact drilling and completion activity levels and thus impact the activity levels of our customers in the pressure pumping industry. However, because we generate a substantial amount of our revenues under long-term supply contracts, we believe we have only limited exposure to short-term fluctuations in the prices of crude oil and natural gas. We do not intend to hedge our indirect exposure to commodity risk.
Interest Rate Risk
As of December 31, 2014, we had $198,500 of principal outstanding under our senior secured term loan facility, with an interest rate of 4.75%. 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 $943 per year.
Credit Risk – Customer Concentration
More than 50% of our volumes are sold to three of our customers. Our customers are generally pressure pumping service providers. This concentration of counterparties operating in a single industry may increase our overall exposure to credit risk in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions. If a customer defaults or if any of our contracts expires in accordance with its terms, and we are unable to renew or replace these contracts, our gross profit and cash flows, and our ability to make cash distributions to our unitholders may be adversely affected.



81


ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Our consolidated financial statements are included in this Annual Report on Form 10-K beginning on page F-1.


82


ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND   FINANCIAL DISCLOSURE
None.

83


ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
Our management, with the participation of our general partner's Co-Chief Executive Officers and Chief Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Annual Report on Form 10-K. Based on such evaluation, our general partner's Co-Chief Executive Officers and Chief Financial Officer have concluded that as of such date, our disclosure controls and procedures were effective.
Management’s Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act. Our internal control over financial reporting is a process designed under the supervision of our general partner's Co-Chief Executive Officers and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not detect or prevent misstatements.  Also, projections of any evaluation of the effectiveness to future periods are subject to risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
As of December 31, 2014, our management assessed the effectiveness of our internal control over financial reporting based on the criteria for effective internal control over financial reporting established in Internal Control - Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission in 2013. Based on the assessment, management determined that we maintained effective internal control over financial reporting as of December 31, 2014, based on those criteria.
The effectiveness of our internal control over financial reporting as of December 31, 2014 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their audit report which appears herein.
Changes in Internal Controls Over Financial Reporting
During the quarter ended December 31, 2014, there have been no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.


84


ITEM 9B. OTHER INFORMATION
None.

85


PART III

86


ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Management of Hi-Crush Partners LP
We are managed and operated by the board of directors and executive officers of our general partner. As of February 27, 2015, all of our outstanding subordinated units and incentive distribution rights were owned by 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 the independent directors. Our unitholders are not entitled to elect our general partner or its directors or otherwise directly participate in our management or operation. Our general partner owes certain duties to our unitholders as well as a fiduciary duty to its owners.
Our general partner has ten directors, three of whom are independent as defined under the independence standards established by the NYSE and the Exchange Act. The NYSE does not require a listed publicly-traded partnership, such as ours, to have a majority of independent directors on the board of directors of our general partner or to establish a compensation committee or a nominating committee. However, our general partner is required to have an audit committee of at least three members, and all its members are required to meet the independence and experience standards established by the NYSE and the Exchange Act. As of December 31, 2014, the following directors served on the audit committee:
Name
 
Independence Status
John F. Affleck-Graves
 
Independent
John Kevin Poorman
 
Independent
Joseph C. Winkler III
 
Independent
All of the executive officers of our general partner allocate their time between managing our business and affairs and the business and affairs of our sponsor. While the amount of time that our executive officers devote to our business and the business of our sponsor varies in any given year based on a variety of factors, we currently estimate that each of our executive officers spend approximately 80% of their time on the management of our business. Our executive officers devote as much time to the management of our business and affairs as is necessary for the proper conduct of our business and affairs.
Following the IPO on August 16, 2012, neither our general partner nor our sponsor receive any management fee or other compensation in connection with our general partner’s management of our business, but we reimburse our general partner and its affiliates, including our sponsor, for all expenses they incur and payments they make on our behalf. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our partnership agreement provides that our general partner determines in good faith the expenses that are allocable to us.
In evaluating director candidates, our sponsor assesses whether a candidate possesses the integrity, judgment, knowledge, experience, skill and expertise that are likely to enhance the board’s ability to manage and direct our affairs and business, including, when applicable, to enhance the ability of committees of the board to fulfill their duties.


87


Executive Officers and Directors of Our General Partner
The following table shows information for the executive officers and directors of our general partner. Directors are appointed for a one-year term and hold office until their successors have been elected or qualified or until the earlier of their death, resignation, removal or disqualification. Executive officers serve at the discretion of the board. There are no family relationships among any of our directors or executive officers. Some of our directors and all of our executive officers also serve as executive officers of our sponsor.
Name
 
Age
 
Position With Our General Partner
Robert E. Rasmus
 
57
 
Co-Chief Executive Officer and Director
James M. Whipkey
 
57
 
Co-Chief Executive Officer and Director
Jefferies V. Alston, III
 
37
 
Chief Operating Officer and Director
Laura C. Fulton
 
51
 
Chief Financial Officer
Mark C. Skolos
 
55
 
General Counsel and Secretary
William H. Fehr
 
59
 
Executive Vice President
Chad M. McEver
 
42
 
Vice President
John F. Affleck-Graves
 
64
 
Director
Gregory F. Evans
 
34
 
Director
John R. Huff
 
68
 
Director
John Kevin Poorman
 
63
 
Director
Trevor M. Turbidy
 
47
 
Director
Graham R. Whaling
 
60
 
Director
Joseph C. Winkler III
 
63
 
Director
Robert E. Rasmus—Co-Chief Executive Officer. Mr. Rasmus is a co-founder of Hi-Crush Proppants LLC and has served as its Co-Chief Executive Officer since its formation in October 2010. Mr. Rasmus was named Co-Chief Executive Officer and appointed to the board of directors of our general partner in May 2012. Mr. Rasmus was a founding member of Red Oak Capital Management LLC (“ROCM”) in June 2002 and has served as Managing Director since inception. ROCM’s business model centered on partnering with the largest oil services companies in unconventional basins in the United States. Prior to the founding of ROCM, Mr. Rasmus was the President of Thunderbolt Capital Corp., a venture firm focused on start-up and early stage private equity investments. Previously, Mr. Rasmus started, built and expanded a variety of domestic and international capital markets and corporate finance businesses. Mr. Rasmus was the Senior Managing Director of Banc One Capital Markets, Inc. (formerly First Chicago Capital Markets, Inc.) where he was responsible for the high yield and private placement businesses while functioning as a member of the management committee. Prior thereto, Mr. Rasmus was the Managing Director and Head of Investment Banking in London for First Chicago Ltd. Mr. Rasmus holds a BA in Government and International Relations from the University of Notre Dame. We believe that Mr. Rasmus’ industry experience and deep knowledge of our business makes him well-suited to serve on the board of directors of our general partner.
James M. Whipkey—Co-Chief Executive Officer. Mr. Whipkey has a 35 year background in the oil and natural gas industry with broad experience in both technical and financial areas. Mr. Whipkey is a co-founder of Hi-Crush Proppants LLC and has served as its Co-Chief Executive Officer since its formation in October 2010. Mr. Whipkey was named Co-Chief Executive Officer and appointed to the board of directors of our general partner in May 2012. Mr. Whipkey was a founding member of ROCM in June 2002 and has served as Managing Director since inception. Prior to the founding of ROCM, Mr. Whipkey was an equity analyst covering the exploration and production sector, most recently as a Managing Director at ABN Amro Bank N.V. From 1997 to 2000, Mr. Whipkey was the Chief Financial Officer and Treasurer for NYSE-listed Benton Oil and Gas Company. Prior thereto, Mr. Whipkey worked in a number of investment banking positions managing a wide range of relationships and responsibilities in the energy sector. His various roles included energy derivatives trading at Phibro Energy Inc., investment banking at Kidder, Peabody & Co., and stock analysis at Lehman Brothers Holdings Inc., where he won “All-Star” recognition from the Wall Street Journal in both the E&P and oil service sectors. Mr. Whipkey began his career as a petroleum engineer with Amoco Corporation where he spent five years in operations, drilling and reservoir simulation roles. Mr. Whipkey holds a BS in Petroleum and Natural Gas Engineering from The Pennsylvania State University and an MBA in Finance from the University of Chicago. We believe that Mr. Whipkey’s experience in senior financial management and knowledge of our business serve him well as a member of the board of directors of our general partner.




88


Jefferies V. Alston, III—Chief Operating Officer. Mr. Alston has served as Chief Operating Officer of Hi-Crush Proppants LLC since May 2011 and was appointed Chief Operating Officer and appointed to the board of directors of our general partner in May 2012. Mr. Alston founded Trinity Consulting, LLC (“Trinity”) in December 2009, where he designed and managed construction of numerous frac sand processing facilities and became one of the leading consultants in the industry, until dissolving Trinity to join Hi-Crush Proppants LLC. Mr. Alston worked for Alston Equipment Company, Inc. (“Alston Equipment”) from February 1999 until he founded Trinity in December 2009. While at Alston Equipment, Mr. Alston was responsible for sales, growth initiatives and customer relations. Mr. Alston attended The University of Southern Mississippi and Southeastern Louisiana University. With his extensive knowledge of the frac sand industry, we believe Mr. Alston brings substantial experience and leadership skills to the board of directors of our general partner.
Laura C. Fulton—Chief Financial Officer. Ms. Fulton has served as Chief Financial Officer of Hi-Crush Proppants LLC since April 2012. In May 2012, Ms. Fulton was appointed to Chief Financial Officer of our general partner. On February 26, 2013, Ms. Fulton was elected director of Targa Resources Corp. and serves on the audit committee and compensation committee. From March 2008 to October 2011, Ms. Fulton served as the Executive Vice President, Accounting and then Executive Vice President, Chief Financial Officer of AEI Services, LLC (“AEI”), an owner and operator of essential energy infrastructure assets in emerging markets. Prior to AEI, Ms. Fulton spent 12 years with Lyondell Chemical Company in various capacities, including as general auditor responsible for internal audit and the Sarbanes-Oxley certification process, and as the assistant controller. Previously, Ms. Fulton worked for Deloitte & Touche in its audit and assurance practice for 11 years. Ms. Fulton is a CPA and graduated cum laude from Texas A&M University with a BBA in Accounting. Ms. Fulton is a member of the American Institute of Certified Public Accountants and serves on the Accounting Department Advisory Board at Texas A&M University.
Mark C. Skolos—General Counsel and Secretary. Mr. Skolos was appointed General Counsel of Hi-Crush Proppants LLC in April 2012 and named General Counsel and Secretary of our general partner in May 2012. Prior to joining Hi-Crush Proppants LLC, Mr. Skolos was a shareholder at the law firm of Weld, Riley, Prenn and Ricci S.C. (“Weld Riley”) from September 2011 to April 2012. Mr. Skolos worked as an attorney for Skolos, Millis and Matousek, S.C., or its predecessor firms (“Skolos Millis”), for 26 years prior to its merger with Weld Riley in April 2012. Mr. Skolos was made a shareholder at Skolos Millis in 1990. In his private practice, Mr. Skolos represented developers, businesses and local units of government on issues of government regulation, land use and real estate. Mr. Skolos has extensive experience representing companies in the non-metallic mining and processing industry on a wide spectrum of issues, including permitting, land acquisition and government relations. He graduated from the University of Wisconsin Law School in 1985 with a JD. Mr. Skolos has served as President of the Tri-County Bar Association of Wisconsin and acted as both Circuit Court and Family Court Commissioner in the State of Wisconsin.
William H. Fehr—Executive Vice President. Mr. Fehr was named an Executive Vice President of Hi-Crush Partners LP on June 11, 2013. Mr. Fehr co-founded D&I, acquired by Hi-Crush Partners in June 2013, and currently oversees our sales and marketing, supplier and rail relationship management, car logistics and finance functions. Prior to D&I, Mr. Fehr founded and operated several companies in the natural resource and logistics industries. In 2005, Mr. Fehr founded Chestnut Oil, a shallow oil and gas drilling and production company. In 1997, Mr. Fehr founded and assumed the role of President & CEO of the companies Agile Stone Systems and Rock&Rail, Inc. Agile Stone Systems was a greenfield operation located in Parkdale, CO which acquired and permitted acreage with sand, gravel and granite mines. Rock&Rail, Inc. was used for the purposes of purchasing the rail through the Royal Gorge of Colorado and to then acquire track rights from the BNSF. Rock&Rail was later expanded and developed a unit train aggregate transloading facility in Colorado Springs. Agile Stone and Rock&Rail were sold in 2001 to Colorado Materials, Inc. In 1986 Mr. Fehr became Chairman and CEO of Berks Products Corporation (“BPC”), a family-owned business. BPC was an integrated material supply, mining, road building and petroleum marketing company. Mr. Fehr is a graduate of the University of Arizona with a BS in International Agriculture Economics and holds an MBA from the Thunderbird School of Global Management.
Chad M. McEver—Vice President. Mr. McEver has served as Vice President of Hi-Crush Proppants LLC since its inception in October 2010. Mr. McEver was named Vice President of our general partner in May 2012. Mr. McEver joined ROCM as an Associate in 2004 and has served as Vice President since 2010. In executing the business model of ROCM, Mr. McEver has been responsible for analysis, execution and origination of projects with exploration and production and oilfield services companies and ROCM’s co-investors. From 2001 to 2004, Mr. McEver was a Director at EnerCom, Inc., an investor relations consulting firm exclusively serving the energy industry. From 1999 to 2001, Mr. McEver was an analyst in the investment banking energy group at Raymond James & Associates. Mr. McEver holds a BBA from Stephen F. Austin State University and an MBA in Finance from the University of Denver.





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

Gregory F. Evans—Director. Mr. Evans has served as a director of Hi-Crush Proppants LLC since January 2014 and was appointed to the board of directors of our general partner in February 2014. Mr. Evans currently serves as a Principal of Avista Capital Partners, where he has worked since 2005. From 2003 to 2005, Mr. Evans was an Analyst at DLJ Merchant Banking Partners. Prior to joining DLJ Merchant Banking Partners, he was an Analyst in Credit Suisse First Boston’s Investment Banking Department. Mr. Evans holds an BBA in Finance from the University of Texas at Austin. We believe that Mr. Evans brings financial and analytical expertise in the energy sector, including experience as a director of numerous energy-related companies, to the board of directors of our general partner.
John R. Huff—Director. Mr. Huff has served as a director of Hi-Crush Proppants LLC since May 2011 and was appointed to the board of directors of our general partner in May 2012. Mr. Huff has served as Chairman of the board of directors of Oceaneering International, Inc. (“Oceaneering”) since 1990 and served as its Chief Executive Officer from 1986 to 2006. Prior to joining Oceaneering, Mr. Huff served as Chairman, President and Chief Executive Officer of Western Oceanic, Inc. from 1972 to 1986. In addition to his service as chairman of the board of directors of Oceaneering, Mr. Huff has served as a member of the board of directors of Suncor Energy, Inc. since 1998. Mr. Huff also served as a member of the board of directors of Rowan Companies, Inc. from April 2006 to May 2009, of KBR, Inc. from April 2007 to April 2014 and of BJ Services Company from 1992 to April 2010. Mr. Huff received a Bachelor’s degree in Civil Engineering from Georgia Tech and attended the Harvard Business School’s Program for Management Development. Mr. Huff is a Registered Professional Engineer in the State of Texas and a member of the National Academy of Engineering, Washington D.C. We believe that Mr. Huff’s substantial knowledge of energy-related businesses, as well as his considerable experience as a director of public companies, has prepared him well to serve on the board of directors of our general partner.
John Kevin Poorman—Director. Mr. Poorman joined the board of directors of our general partner in August 2013 and serves as a member of the Audit Committee and Conflicts Committee. Since June 2013, Mr. Poorman has been Chief Executive Officer of PSP Capital Partners, LLC and Pritzker Realty Group, LLC, investment managers for affiliated entities in real estate and other non-real estate business. Pritzker Realty Group, LLC is also an operator of real estate. Mr. Poorman is responsible for implementing and overseeing each company's strategic direction. He is also Executive Chairman of Vi Senior Living (formerly Classic Residence by Hyatt). Mr. Poorman previously served as an officer and director of several businesses owned by interests of the extended Pritzker family. Mr. Poorman is the past Chairman of the Board of Trustees of the Loyola University of New Orleans and currently serves as a director of The New Orleans Jazz Orchestra, Inc. Mr. Poorman also serves as President and as director of The Barack Obama Foundation. Prior to joining Hyatt Hotels Corporation in 1988, Mr. Poorman was a partner in the Dallas-based law firm of Johnson & Swanson. We believe that Mr. Poorman’s business leadership skills make him well-suited to serve on the board of directors of our general partner.
Trevor M. Turbidy—Director. Mr. Turbidy has served as a director of Hi-Crush Proppants LLC since May 2011 and was appointed to the board of directors of our general partner in May 2012. Mr. Turbidy has served as an energy industry advisor for Avista Capital Partners since 2007. Prior to joining Avista Capital Partners, Mr. Turbidy served as Chief Executive Officer of Trico Marine Services (“Trico”), an international provider of marine support vessel services to the offshore oil and gas industry from 2005 to 2007. Prior to that, Mr. Turbidy was Chief Financial Officer of Trico from 2003 to 2005, functioned as the Chief Restructuring Officer during the company’s restructuring and subsequently was promoted to Chief Executive Officer after its successful completion. Prior to his service at Trico, Mr. Turbidy spent more than a decade with Donaldson, Lufkin & Jenrete Inc. (“DLJ”) and Credit Suisse First Boston in their investment banking divisions. During his tenure with DLJ and Credit Suisse First Boston, Mr. Turbidy focused on the energy sector, principally offshore and land drilling contractors, seismic service providers, oilfield equipment manufacturers, offshore support vessel providers and exploration and production companies, as well as regional opportunities in the Southwest. Mr. Turbidy previously served as a director of Grey Wolf, Inc., Precision Drilling Corporation and Trico Marine Services Inc., as well as a number of private companies in the energy industry. Mr. Turbidy holds an AB in Economics from Duke University. We believe that Mr. Turbidy’s substantial management-level experience with public and private companies, together with his considerable knowledge of the energy industry as a whole, are of great value to the board of directors of our general partner.

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Graham R. Whaling—Director. Mr. Whaling was appointed to the board of directors of our general partner in February 2015 and has a 35 year background in the energy industry. Since 2014, Mr. Whaling has served as an energy industry advisor for Avista Capital Partners. Prior to joining Avista Capital Partners, Mr. Whaling served as Chief Executive Officer of Parkman Whaling, an oil and gas investment banking advisory firm, which he co-founded in July 2007. Prior to that, Mr. Whaling was chairman and Chief Executive Officer of Laredo Energy, L.P., which he co-founded in 2001. Mr. Whaling has also been a Managing Director at DLJ Merchant Banking Partners, Chairman and Chief Executive Officer of Monterey Resources Inc. and Chief Financial Officer of Santa Fe Energy Resources, Inc. Mr. Whaling holds an M.B.A. from the Wharton School of the University of Pennsylvania and a bachelor’s degree in petroleum engineering from the University of Texas.  We believe that Mr. Whaling’s substantial management-level experience, together with his extensive knowledge of and background in the energy industry, make him particularly well-qualified to serve on the board of directors of our general partner.
Joseph C. Winkler III—Director. Mr. Winkler joined the board of directors of our general partner in connection with our IPO and serves as the Chairman of the Audit Committee and Conflicts Committee. Mr. Winkler served as Chairman and Chief Executive Officer of Complete Production Services, Inc. (“Complete”), a provider of specialized oil and gas services and equipment in North America, from March 2007 until February 2012, at which time Complete was acquired by Superior Energy Services, Inc. From June 2005 to March 2007, Mr. Winkler served as Complete’s President and Chief Executive Officer. Prior to that, from March 2005 until June 2005, Mr. Winkler served as the Executive Vice President and Chief Operating Officer of National Oilwell Varco, Inc., an oilfield capital equipment and services company, and from May 2003 until March 2005 as the President and Chief Operating Officer of the company’s predecessor, Varco International, Inc. (“Varco”). From April 1996 until May 2003, Mr. Winkler served in various other capacities with Varco and its predecessor, including Executive Vice President and Chief Financial Officer. From 1993 to April 1996, Mr. Winkler served as the Chief Financial Officer of D.O.S., Ltd., a privately held provider of solids control equipment and services and coil tubing equipment to the oil and gas industry, which was acquired by Varco in April 1996. Prior to joining D.O.S., Ltd., Mr. Winkler served as Chief Financial Officer of Baker Hughes INTEQ, and served in a similar role for various companies owned by Baker Hughes Incorporated including Eastman/Telco and Milpark Drilling Fluids. Mr. Winkler is a member of the board of directors of Dresser-Rand Group, Inc., a NYSE-listed provider of rating equipment solutions, and serves on the Compensation and Nominating and Governance Committees. Mr. Winkler is also a member of the board of directors of Commercial Metals Company, a vertically integrated Fortune 500 steel company, and serves on its Finance Committee, and a member of the board of directors of Eclipse Resources Corporation, an independent exploration and production company, and serves on its audit and compensation committees. Mr. Winkler received a BS degree in Accounting from Louisiana State University. We believe that Mr. Winkler’s many years of operational, financial, international and capital markets experience, a significant portion of which was with publicly traded companies in the oil and gas services, manufacturing and exploration and production industries, make him particularly well-suited to serve on the board of directors of our general partner.
















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Director Independence
As of December 31, 2014, three of our directors were independent.
Committees of the Board of Directors
The board of directors of our general partner maintains an audit committee and a conflicts committee. As permitted by NYSE rules, we do not currently have a compensation committee, but rather the board of directors of our general partner approves equity grants to directors and employees.
Audit Committee
We are required to have an audit committee of at least three members, and all its members are required to meet the independence and experience standards established by the NYSE and the Exchange Act. The audit committee assists the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and partnership policies and controls. The audit committee has the sole authority to (1) retain and terminate our independent registered public accounting firm, (2) approve all auditing services and related fees and the terms thereof performed by our independent registered public accounting firm, and (3) pre-approve any non-audit services and tax services to be rendered by our independent registered public accounting firm. The audit committee is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm is given unrestricted access to the audit committee and our management, as necessary. Messrs. Winkler III, Affleck-Graves and Poorman are the members of the audit committee, with Mr. Winkler III currently serving as chairman.
The board of directors of our general partner has determined that Mr. Winkler III qualifies as an “audit committee financial expert,” as such term is defined under SEC rules.
The audit committee has (1) reviewed and discussed the audited financial statements with management, (2) discussed with the independent auditors the matters required by PCAOB Auditing Standard No. 16, Communications with Audit Committees, (3) received written disclosures and the letter from the independent accountants required by applicable requirements of the PCAOB regarding the independent accountant's communications with the audit committee concerning independence and has discussed with the independent accountant the independent accountant's independence, and (4) recommended to the board of directors of our general partner that the audited financial statements be included in the Partnership's annual report on Form 10-K for the last fiscal year.
Conflicts Committee
Three independent members of the board of directors of our general partner serve on the conflicts committee to review specific matters that the board believes may involve conflicts of interest and determines to submit to the conflicts committee for review. The conflicts committee determines if the resolution of the conflict of interest is in our best interest. The members of the conflicts committee may not be officers or employees of our general partner or directors, officers or employees of its affiliates, including our sponsor, and must meet the independence standards established by the NYSE and the Exchange Act to serve on an audit committee of a board of directors, along with other requirements in our partnership agreement. Any matters approved by the conflicts committee are conclusively deemed to be in our best interest, approved by all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders. Messrs. Winkler III, Affleck-Graves and Poorman are the members of the conflicts committee, with Mr. Winkler III currently serving as chairman.
Section 16(a) Beneficial Ownership Reporting Compliance
Pursuant to Section 16(a) of the Exchange Act, certain officers and directors of our general partner, and persons beneficially owning more than 10% of our units, are required to file with the SEC reports of their initial ownership and changes in ownership of our units. These officers and directors, and persons beneficially owning more than 10% of our units are also required by SEC regulations to furnish us with copies of all Section 16(a) forms they file. Based solely on a review of Forms 3, 4 and 5 and amendments thereto furnished to us and written representations from reporting persons that no other reports were required for those persons, we believe that during 2014, all officers and directors, and persons beneficially owning more than 10% of our units who were required to file reports under Section 16(a) complied with such requirements on a timely basis except that a Form 4 filed by Mr. Huff with respect to the award of common units in the Partnership representing limited partner units was not timely filed.





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Corporate Governance Matters
We have a Code of Business Conduct and Ethics for directors, executive officers and employees that applies to, among others, the principal executive officers, principal financial officer and principal accounting officer or controller of our general partner, as required by SEC and NYSE rules. Furthermore, we have Corporate Governance Guidelines and charters for our Audit Committee and Conflicts Committee. Each of the foregoing is available on our website at www.hicrushpartners.com in the “Corporate Governance” section. We provide copies, free of charge, of any of the foregoing upon receipt of a written request to Hi-Crush Partners LP, Three Riverway, Suite 1550, Houston, Texas 77056, Attn: General Counsel. We disclose amendments and director and executive officer waivers with regard to the Code of Business Conduct and Ethics, if any, on our website or by filing a Current Report on Form 8-K to the extent required.
The certifications of our general partner’s Co-Chief Executive Officers and Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act have been included as exhibits to this Annual Report on Form 10-K.
Communication with the Board of Directors
A holder of our units or other interested party who wishes to communicate with the directors of our general partner may do so by contacting our corporate secretary at the address or phone number appearing on the front page of this Annual Report on Form 10-K. Communications will be relayed to the intended recipient of the board of directors of our general partner except in instances where it is deemed unnecessary or inappropriate to do so pursuant to our communications policy, which is filed available on our website at www.hicrushpartners.com in the “Corporate Governance” section. Any communications withheld under those guidelines will nonetheless be recorded and available for any director who wishes to review them.
Executive Sessions of Non-Management Directors
The board of directors of our general partner holds regular executive sessions in which the independent directors meet without any non-independent directors or members of management. The purpose of these executive sessions is to promote open and candid discussion among the independent directors. The director who presides at these meetings, the Lead Director, is chosen by the board of directors to serve until the first meeting of the Board to occur after the first anniversary of the date that the Lead Director is chosen. The current Lead Director is Mr. Winkler III.


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ITEM 11. EXECUTIVE COMPENSATION
(All amounts presented in dollars)
Compensation Discussion and Analysis
General
As a publicly traded limited partnership, we do not have directors, officers or employees. Instead, we are managed by the board of directors of our general partner, Hi-Crush GP LLC, and the executive officers of our general partner perform all of our management functions. Other than Mr. McEver who is employed by Hi-Crush Services, a subsidiary of our sponsor, Hi-Crush Proppants LLC, all of our general partner’s named executive officers are employed by our sponsor. Under the Services Agreement, we reimburse Hi-Crush Services, on a monthly basis, for the allocable expenses that it and our sponsor incurs in compensating our general partner’s named executive officers. Please read “Item 13. Certain Relationships and Related Transactions, and Director Independence-Other Transactions with Related Persons” for more information about the Services Agreement.
Other than equity-based incentive grants under our long-term incentive plan, our sponsor as the ultimate employer of our named executive officers has responsibility and authority for non-equity based compensation related decisions for our Co-Chief Executive Officers and our Chief Operating Officer and, upon consultation with and recommendations by our Co-Chief Executive Officers, for our Chief Financial Officer and General Counsel. Although our sponsor has the ultimate responsibility and authority for non-equity based compensation related decisions for our named executive officers, it regularly consults with, receives recommendations from, and obtains the approval of, the board of directors of our general partner with respect to non-equity based compensation related decisions. All compensation decisions for employees of Hi-Crush Services, including those for the individuals who are executive officers of our general partner, are made at the discretion of our Co-Chief Executive Officers, subject to approval by our sponsor and consultation with the board of directors of our general partner. All determinations with respect to equity awards made under the Partnership’s Long-Term Incentive Plan, or LTIP, are made by the board of directors of our general partner, following the recommendation of our sponsor and the approval of the board of directors of our general partner and, where appropriate, the conflicts committee of the board of directors of our general partner.
For the year ended December 31, 2014, the named executive officers, or NEOs, of our general partner were the following:
Robert E. Rasmus, Co-Chief Executive Officer (Principal Executive Officer)
James M. Whipkey, Co-Chief Executive Officer (Principal Executive Officer)
Laura C. Fulton, Chief Financial Officer (Principal Financial Officer)
Jefferies V. Alston, III, Chief Operating Officer
Mark C. Skolos, General Counsel and Secretary
Chad M. McEver, Vice President
Distributions to Our General Partner
Our general partner is directly owned by our sponsor, which is partially-owned by certain of our named executive officers. We pay quarterly distributions to our sponsor in accordance with our partnership agreement with respect to its ownership of its limited partner interests and the incentive distribution rights as specified in our partnership agreement. The amount of each quarterly distribution that we pay to our sponsor is based solely on the provisions of our partnership agreement, which agreement specifies the amount of cash we distribute to our sponsor based on the amount of cash that we distribute to our limited partners each quarter. Accordingly, the cash distributions we make to our sponsor bear no relationship to the level or components of compensation of our named executive officers.
Our Compensation Philosophy
Our executive compensation program is intended to align the interests of our management team with those of our unitholders by motivating our executive officers to achieve strong financial and operating results for us, which we believe closely correlate to long-term unitholder value. In addition, our program is designed to achieve the following objectives:
attract, retain and reward talented executive officers and key management employees by providing total compensation competitive with that of other executive officers;
motivate executive officers and key management employees to achieve strong financial and operational performance;
emphasize performance-based compensation, balancing short-term and long-term results; and
reward individual performance.
Methodology - Advisors and Peer Companies
We employ a compensation philosophy that emphasizes pay-for-performance based on a combination of the Partnership’s performance and the individual’s impact on the Partnership’s performance, advancement of our business strategies, levels of responsibility, skills and experience. We believe this pay-for-performance approach generally aligns the interests of our named executive officers with that of our unitholders, and at the same time enables us to maintain a lower level of base salary overhead in the event our operating and financial performance fails to meet expectations. Our executive compensation program is designed to attract and retain individuals with the background and skills necessary to successfully execute our business model in a demanding environment, to motivate those individuals to reach near-term and long-term goals in a way that aligns their interest with that of our unitholders, and to reward success in reaching such goals.

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In early 2014, we engaged the services of BDO USA, LLP, or BDO, a compensation consultant, to conduct a study to assist us in establishing overall compensation targets for our named executive officers for 2014. We consider BDO to be independent of the Partnership and therefore the work performed by BDO does not create a conflict of interest. The BDO study was based on compensation as reported in the proxy statements, Form 8-K filings and the annual reports on Form 10-K for a peer company group comprising energy focused partnerships and certain competitors.
The study was comprised of the following peer companies:
Access Midstream Partners, L.P.
American Midstream Partners, LP
Atlas Pipeline Partners, L.P.
Boardwalk Pipeline Partners, LP
Carbo Ceramics Inc.
Crestwood Equity Partners LP
DCP Midstream Partners, LP
Eagle Rock Energy Partners, L.P.
EnLink Midstream Partners, LP
Genesis Energy, L.P.
Markwest Energy Partners, L.P.
Niska Gas Storage Partners LLC
NuStar Energy L.P.
PVR Partners, L.P.
Regency Energy Partners LP
Summit Midstream Partners, LP
Targa Resources Partners LP
U.S. Silica Holdings, Inc.
The compensation analysis provided by BDO covered all major components of total compensation, including annual base salary, annual short-term cash incentive and long-term incentive awards for the senior executives of these companies. The board of directors of our general partner utilized the information provided by BDO to compare the levels of annual base salary, annual short-term cash incentive and long-term equity incentive awards at the peer companies with those of its named executive officers to ensure that compensation of our named executive officers is both consistent with our compensation philosophy and competitive with the compensation for executive officers the peer companies. The board of directors of our general partner also considered and reviewed the results of the study performed by BDO to ensure the results indicated that our compensation programs were yielding a competitive total compensation model prioritizing incentive-based compensation and rewarding achievement of short and long-term performance objectives.
Components of Executive Compensation
There are principally three components of compensation that are used in our executive compensation program - base salary, annual short-term cash incentive and long-term equity incentive awards. Cash incentives and equity incentives (as opposed to base salary and benefits) represent the performance driven elements of the compensation program. The determination of each individual’s short-term cash incentives will reflect their relative contribution to achieving or exceeding annual goals, and the determination of each individual’s long-term incentive awards will be based on their expected contribution in respect of longer term performance objectives.
Base Salary
Base salary is paid in cash and is paid in order to recognize each executive officer's unique value and contributions to our success in light of salary norms in the industry, to provide our named executive officers with sufficient, regularly paid income and to reflect position and level of responsibility. Our sponsor and the board of directors of our general partner review base salaries on an annual basis and may make adjustments as necessary to maintain a competitive executive compensation structure.
Effective June 1, 2014, our sponsor and the board of directors of our general partner approved an increase of 9% to Ms. Fulton’s annual base salary to $300,000 and 19% to Mr. Skolos’ annual base salary to $250,000. Our sponsor and the board of directors of our general partner deemed such increases to be reasonable based on the results of the BDO study and the expanded roles that each of these individuals serves with respect to the organization subsequent to the acquisition of D&I and the associated increase in responsibility of these individuals in light of the same. Similar to 2013, our Co-Chief Executive Officers and Chief Operating Officer each received an annual base salary of one dollar in 2014.
Annual Short-Term Cash Incentive
Under the annual short-term cash incentive plan, or STI, annual cash incentives are provided to executives to promote the achievement of our performance objectives. For our Co-Chief Executive Officers and Chief Operating Officer, target incentive opportunities are established as a dollar amount. Target incentive opportunities for our other named executive officers under the STI are established as a percentage of base salary. Incentive amounts are intended to provide total cash compensation consistent with opportunities available to executive officers in comparable positions in companies of comparable size when target performance is achieved, below such levels when performance is less than target and above the market median when performance exceeds target, with appropriate adjustments to reflect our organizational structure containing Co-Chief Executive Officers. The BDO study was used to determine the competitiveness of the incentive opportunity for comparable positions. For Ms. Fulton, Mr. Skolos and Mr. McEver, STI payments are generally paid in cash in February of each year for the prior fiscal year’s performance.
In order to provide a further focus on long-term value creation and enhance executive retention, our sponsor and the board of directors of our general partner determined that for our Co-Chief Executive Officers and Chief Operating Officer in 2014, 50% of each of such named executive officer’s STI payment will be paid in cash in February for the prior fiscal year’s performance and the remaining 50% of such STI payment will be awarded as performance based vesting phantom limited partner units, or PPUs, under the Partnership’s Long-Term Incentive Plan, with the PPUs vesting at the end of a three-year performance period. Please see “Compensation Discussion and Analysis-Components of Executive Compensation-Long-Term Incentive Compensation” below for a discussion regarding the PPUs.

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In 2014, the STI objectives were initially designed and proposed by our Co-Chief Executive Officers, working with certain members of the board of directors of our general partner, including the Chairman of the conflicts committee of the board of directors of our general partner. The objectives of the STI were both oriented towards the Partnership and the Hi-Crush enterprise, which includes both Hi-Crush Proppants LLC, the owner of our general partner, and the Partnership combined. The STI objectives approved by our sponsor and the board of directors of our general partner were divided as follows for each of our named executive officers other than Mr. McEver: (1) Partnership objectives accounted for 80% of the STI and (2) applicable strategic individual objectives accounted for 20% of the STI. Mr. McEver’s Partnership objectives and his strategic individual objectives each accounted for 50% of the STI. Individual objectives focus on specific strategic objectives to be targeted by each named executive officer for that particular calendar year. The target STI opportunities for 2014 as a percentage of base salary, or as an established dollar amount, as applicable, were as follows:
Name and Principal Position
 
2014 Targeted STI Opportunity
Robert E. Rasmus, Co-Chief Executive Officer
 
$1,666,667
James M. Whipkey, Co-Chief Executive Officer
 
$1,666,667
Laura C. Fulton, Chief Financial Officer
 
83% of base salary
Jefferies V. Alston, III, Chief Operating Officer
 
$1,666,667
Mark C. Skolos, General Counsel and Secretary
 
83% of base salary
Chad M. McEver, Vice President
 
40% of base salary
For 2014, there were three stated Partnership objectives under the STI, which accounted for 80% of the total STI (the "contingent amount"). These Partnership objectives were the following: (1) achievement of our budget for adjusted EBITDA, which accounted for 50% of the contingent amount, (2) achievement of a targeted annual growth in distributions to unitholders, which accounted for 25% of the contingent amount, and (3) achievement of a targeted year-over-year growth in total unitholder return, which accounted for 25% of the contingent amount. The payout on these Partnership objectives ranged from 0% if the minimum level of performance was not achieved, 50% if the minimum level of performance was achieved, 100% if the target level of performance was achieved and with respect to (x) our Co-Chief Executive Officers and Chief Operating Officer, 150% if the maximum level of performance was achieved and (y) our other named executive officers, 200% if the maximum level of performance was achieved. If the performance level falls between these percentages, payout is determined by straight-line interpolation.
The level of performance achieved in 2014 for each of the Partnership objectives was as follows:
STI Partnership Objectives
 
Level of Performance Achieved 
(1) Adjusted EBITDA
 
Above Maximum
(2) Annual Distribution Growth
 
Above Maximum
(3) Year-over-Year Total Unitholder Return
 
Below Minimum
For 2014, the named executive officers' individual objectives under the STI accounted for 20% of the total STI other than for Mr. McEver’s individual objectives under the STI, which accounted for 50% of the total STI. The individual objectives were based on applicable strategic goals and objectives of the Partnership. Similar to the payout on the Partnership objectives, the payout on the individual objectives range from 0% if the minimum level of performance was not achieved, 50% if the minimum level of performance was achieved, 100% if the target level of performance was achieved and with respect to (x) our Co-Chief Executive Officers and Chief Operating Officer, 150% if the maximum level of performance was achieved and (y) our other named executive officers, 200% if the maximum level of performance was achieved, with straight-line interpolation used to determine the payout if the performance level falls between these percentages. Our sponsor and the board of directors of our general partner may apply discretion in determining actual payouts below stated maximums based on its assessment of the Partnership’s overall performance for the year.
Early in 2015, management prepared a report on the achievement of the Partnership objectives and the individual objectives. These results were reviewed and approved by our sponsor and the board of directors of our general partner in January 2015, including a calculation of the percentage achievement of each objective for purposes of the STI program. The total payout for each named executive officer under the STI for fiscal year 2014, including both Partnership objectives and individual objectives, as a percentage of the named executive officer’s target was as follows:
Name and Principal Position
 
2014 STI Payout Achieved (Percentage of Target)
Robert E. Rasmus, Co-Chief Executive Officer
 
120%
James M. Whipkey, Co-Chief Executive Officer
 
120%
Laura C. Fulton, Chief Financial Officer
 
170%
Jefferies V. Alston, III, Chief Operating Officer
 
120%
Mark C. Skolos, General Counsel and Secretary
 
156%
Chad M. McEver, Vice President
 
116%


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Long-Term Incentive Compensation
In connection with our initial public offering, the board of directors of our general partner adopted the LTIP for employees, officers, consultants and directors of our general partner and its affiliates, including Hi-Crush Services LLC, who perform services for us. All Hi-Crush Services LLC employees and each of our named executive officers, are eligible to participate in the LTIP. The LTIP provides for the grant of restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights, other unit-based awards and unit awards.
The LTIP’s objective is to provide a focus on long-term value creation and enhance executive retention. In addition to the PPUs granted in 2015 to our Co-Chief Executive Officers and Chief Operating Officer under the LTIP for amounts earned in 2014 under the STI (discussed above), the board of directors of our general partner approved the issuance under our LTIP in June 2014 of PPUs to each of our named executive officers other than Mr. McEver.
The number of PPUs that will vest will range from 0% to 200% of the number of initially granted PPUs and is dependent on the Partnership’s total unitholder return, or TUR, over a three-year performance period compared to the TUR of each entity in the Alerian MLP Index from the first day of the performance period continuing through the last day of the performance period. Each PPU represents the right to receive, upon vesting, one common unit representing limited partner interests in the Partnership. The PPUs are also entitled to forfeitable distribution equivalent rights, or DERs, which accumulate during the performance period and are paid in cash on the date of settlement. The amount paid on the DERs will equal the quarterly distributions actually paid on the underlying securities during the performance period. Termination of employment for any reason will result in the forfeiture of any unvested units and unpaid DERs. We believe that utilizing total unitholder return as the long-term performance measure for these awards provides incentive for the continued growth of our operating footprint and distributions to unitholders. The PPUs will vest if the named executive officer continuously provides services to the Partnership from the date of grant until the end of the performance period.
If our TUR ranking among the companies in the group over the performance period is below the 25th percentile, 0% of the performance units will vest. If our TUR ranking over the performance period is greater than the 25th percentile but less than or equal to the 50th percentile, 50% to 100% of the performance units will vest. If our TUR ranking over the performance period is greater than the 50th percentile but less than or equal to the 75th percentile, 100% to 200% of the performance units will vest. If our TUR ranking over the performance period is greater than the 75th percentile, 200% of the performance units will vest. The number of phantom units that vest between applicable percentiles will be determined by straight-line interpolation. In addition, the board of directors of the general partner has discretion to increase or decrease the number of phantom units earned by up to 20%.
To determine the number of PPUs granted to each named executive officer in June 2014, we determined the dollar amount of long-term incentive compensation that we wanted to provide, and then granted the number of PPUs that had a fair market value equal to that amount on the date of grant. For our Co-Chief Executive Officers and Chief Operating Officer, long-term incentive awards were determined using the BDO study for individuals in comparable positions and an analysis of the scope and responsibility of their roles and duties and also reflected the significant contribution of each individual to the Partnership’s profitability and success since the Partnership’s initial public offering in 2012. For our other named executive officers other than Mr. McEver, long-term incentive awards for executives under the plan were established as a percentage of base salary (which reflects position and level of responsibility), with reference to the BDO study data for individuals in comparable positions.
The target 2014 long-term incentive opportunities, expressed as a dollar amount or percentage of base salary, as applicable, and the number of PPUs awarded in June 2014, were as follows:
Name and Principal Position
 
2014 Long-Term Incentive Award Value
 
2014 PPUs Awarded (1)
Robert E. Rasmus, Co-Chief Executive Officer
 
$833,365
 
16,644
James M. Whipkey, Co-Chief Executive Officer
 
$833,365
 
16,644
Laura C. Fulton, Chief Financial Officer
 
100% of base salary
 
6,991
Jefferies V. Alston, III, Chief Operating Officer
 
$833,365
 
16,644
Mark C. Skolos, General Counsel and Secretary
 
100% of base salary
 
4,994
(1) Represents 100% of the PPUs awarded to the named executive officer. As discussed above, depending on the Partnership’s performance over a three-year period, between 0% and 200% of the performance units will vest. This table does not reflect the PPUs awarded to Messrs. Rasmus, Whipkey and Alston in February 2015 based on achievements of the targets set forth in the STI.










97


Other Compensation
Incentive Profits Interests
Pursuant to their employment agreements, each of Ms. Fulton, Mr. Skolos and Mr. McEver have been granted a 0.75% profits interest, 0.25% profits interest and 0.50% profits interest, respectively, in our sponsor entitling them to receive 0.75%, 0.25% and 0.50%, respectively, of any net distributions by our sponsor after the capital members of the sponsor have received aggregate distributions from our sponsor above applicable threshold amounts for each executive officer. Upon the receipt by the capital members of aggregate distributions from the sponsor above certain incremental thresholds, Mr. McEver’s profits interest increases from 0.50% up to a maximum 0.80% of any net distributions by our sponsor. The profits interests are subject to vesting at the rate of one third per full year of employment for three years. No profits interest was paid to Ms. Fulton, Mr. Skolos or Mr. McEver in 2014. Mr. McEver received a bonus payment from our sponsor in 2014 that put him in substantially the same after-tax position he would otherwise have been had he held a 0.50% profits interest in our sponsor. All profits interest payments and the bonus paid to Mr. McEver are an expense of our sponsor, and the Partnership does not reimburse our sponsor under the Services Agreement for any portion of profits interest payments made or the bonus paid to Mr. McEver by our sponsor.
Benefits
The Partnership does not maintain a defined benefit or pension plan for our named executive officers because it believes such plans primarily reward longevity rather than performance. Hi-Crush Services provides benefits to all of its employees that includes health, dental, vision, basic term life insurance, personal accident insurance and short and long-term disability coverage. Employees provided to us under the Services Agreement, including our named executive officers, are entitled to the same basic benefits. For the year ended December 31, 2014, Hi-Crush Services provided a dollar-for-dollar matching contribution under the 401(k) plan on the first 3% of eligible compensation contributed to the plan, up to $7,800. The 401(k) matching contribution vests in four installments with the first 25% vesting upon completion of one year of service.
Risk Assessment Related to our Compensation Structure
We believe that the compensation plans and programs for our named executive officers, as well as our other employees, are appropriately structured and are not reasonably likely to result in material risk to the Partnership. We believe these compensation plans and programs are structured in a manner that does not promote excessive risk-taking that could harm the value of the Partnership or reward poor judgment. We also believe that compensation has been allocated among base salary and short and long-term compensation in such a way as to not encourage excessive risk-taking. Under our STI, annual cash incentives are provided to our executives to promote achievement of the Partnership’s short-term strategic objectives. The Partnership awards performance phantom limited partner units, which represent the right to receive upon vesting one common unit representing limited partner interests in the Partnership, rather than unit options for equity awards because the phantom units retain value even in a depressed market so that employees are less likely to take unreasonable risks to get, or keep, options “in-the-money.” Finally, the time-based vesting over three years for the Partnership’s long-term incentive awards ensures that the interests of employees align with those of the unitholders of the Partnership for the long-term performance of the Partnership.
Tax and Accounting Implications of Equity-Based Compensation Arrangements
Deductibility of Executive Compensation
We are a partnership and not a corporation for U.S. federal income tax purposes. Therefore, we believe that the compensation paid to our named executive officers is not subject to the deduction limitations under Section 162(m) of the Internal Revenue Code and therefore is generally fully deductible for federal income tax purposes.
Accounting for Unit-Based Compensation
For unit-based compensation arrangements, including equity-based awards issued to our named executive officers, we record compensation expense over the vesting period of the awards, as discussed further in Note 12 to our consolidated financial statements.










98


Board of Directors Report
The board of directors of our general partner has reviewed and discussed with management the “Compensation Discussion and Analysis” presented above. Members of management with whom the board of directors of our general partner had discussions are the Co-Chief Executive Officers. In addition, the board of directors of our general partner engaged the services of BDO USA, LLP, a compensation consultant, to conduct a study to assist us in establishing overall compensation packages for our executives. Based on this review and discussion, we recommended that the “Compensation Discussion and Analysis” referred to above be included in this Annual Report on Form 10-K for the year ended December 31, 2014.
Board of Directors
John F. Affleck-Graves
Jefferies V. Alston, III
Gregory F. Evans
John R. Huff
John Kevin Poorman
Robert E. Rasmus
Trevor M. Turbidy
R. Graham Whaling
James M. Whipkey
Joseph C. Winkler III
The foregoing report shall not be deemed to be incorporated by reference by any general statement or reference to this Annual Report on Form 10-K into any filing under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended, except to the extent that we specifically incorporate this information by reference, and shall not otherwise be deemed filed under those Acts.





















99


Compensation Tables
Summary Compensation Table
The following table shows the compensation paid or otherwise awarded to (i) our principal executive officers, (ii) our principal financial officer and (iii) our three most highly compensated executive officers (other than our principal executive officers and principal financial officer) serving at the end of fiscal year 2014 for services rendered to us and our subsidiaries during fiscal years 2014, 2013 and 2012, as applicable. The cash compensation paid or awarded by us reflects only the portion of our sponsor’s or Hi-Crush Services’ compensation expense allocated to us by Hi-Crush Services under the Services Agreement.
Name and Principal Position
 
Year
 
Salary ($)
 
 
Bonus ($)(2)
 
Equity Awards($) (3)
 
Non-Equity Incentive Plan Compensation ($)(4)
 
All Other Compensation ($) (6)
 
 
Total $
Robert E. Rasmus
Co-Chief Executive Officer
 
 
2014
 
1

 
 

 
2,307,589

 

 
27,361

(5)
 
2,334,951

 
2013
 
1

 
 

 

 

 
16,648

(5)
 
16,649

 
2012
 
46,644

(1)
 

 

 

 
22,540

(5)
 
69,184

James M. Whipkey
Co-Chief Executive Officer
 
 
2014
 
1

 
 

 
2,307,589

 

 
20,199

(5)
 
2,327,789

 
2013
 
1

 
 

 

 

 
14,260

(5)
 
14,261

 
2012
 
46,644

(1)
 

 

 

 
19,294

(5)
 
65,938

Laura C. Fulton
Chief Financial Officer
 
 
2014
 
219,231

 
 

 
363,182

 
323,000

 
5,928

 
 
911,341

 
2013
 
151,250

 
 
137,500

 

 
266,000

 
11,023

 
 
565,773

 
2012
 
142,397

(1)
 

 

 

 
4,472

 
 
146,869

Jefferies V. Alston, III
Chief Operating Officer
 
2014
 
1

 
 

 
2,307,589

 

 

 
 
2,307,590

Mark C. Skolos
General Counsel and Secretary
 
 
2014
 
183,335

 
 

 
259,438

 
247,000

 
418

 
 
690,191

 
2013
 
108,654

 
 

 

 
190,000

 
7,176

 
 
305,830

 
2012
 
106,192

(1)
 
50,000

 

 

 
4,256

 
 
160,448

Chad M. McEver
Vice President
 
2014
 
163,400

 
 

 

 
76,000

 
3,790

 
 
243,190

(1)
Represents the actual amount of salary paid to the named executive officer until August 16, 2012, the date of the closing of our IPO. Since August 16, 2012, represents the portion of the base salary paid by our sponsor to the named executive officer that was reimbursable by us under the Services Agreement. Upon the closing of the IPO, Messrs. Rasmus and Whipkey's annual base salary under their respective employment agreements became $1.
(2)
The amounts reported in this column represent (i) discretionary bonuses earned by the named executive officer during the applicable fiscal year, including the portion of any cash bonuses paid by our sponsor to the named executive officer that was reimbursable by us under the Services Agreement and (ii) any bonuses provided for in the named executive officer’s employment agreement.
(3)
Equity award amounts reflect the aggregate grant date fair value of LTIP awards granted for the periods presented, computed in accordance with FASB ASC Topic 718. For Messrs. Rasmus, Whipkey and Alston, a portion of the amounts underlying the equity awards reflects equity grants in 2015 for amounts earned in 2014 under the STI. See Note 12 to our consolidated financial statements for additional assumptions underlying the value of the equity awards.
(4)
Represents amounts paid according to the provisions of the short-term cash incentive plan then in effect. Amounts were earned in the fiscal year indicated but were paid in the next fiscal year. With respect to Messrs. Rasmus, Whipkey and Alston, no compensation expense associated with the cash component of their 2014 STI award was allocated to us by Hi-Crush Services under the Services Agreement.
(5)
Pursuant to a management services agreement entered into between Red Oak Capital Management LLC and our sponsor, our sponsor reimburses Red Oak Capital Management LLC for the health and welfare benefits and coverage paid for Messrs. Rasmus and Whipkey.
(6)
Amounts in this column reflect the amount paid by our sponsor from January 1, 2012 until August 16, 2012, and the amount paid by our sponsor since August 16, 2012 that was reimbursable by us under the Services Agreement since August 16, 2012, for matching 401(k) contributions and premiums paid for health and welfare benefits and coverage.





100


Grants of Plan-Based Awards Table
The following supplemental compensation table shows compensation details on the value of plan-based incentive awards granted during 2014 to our named executive officers.  The table includes awards made during or for 2014.  The information in the table under the caption “Estimated Future Payouts Under Non-Equity Incentive Plan Awards” represents the threshold, target and maximum amounts payable under the short-term cash incentive plan for performance in 2014.  Amounts actually paid under that plan for 2014 that were allocated to us by Hi-Crush Services under the Services Agreement are set forth in the Summary Compensation Table under the caption “Non-Equity Incentive Plan Compensation.” Information under the “Grant Date Fair Value of LTIP Awards” represents the June 2014 PPU grants to our named executive officers under the Partnership’s LTIP and the PPUs granted to Messrs. Rasmus, Whipkey and Alston in February 2015 under our LTIP based on the achievement of the targets set forth in the STI. These amounts are set forth in the Summary Compensation Table under the caption “Equity Awards”.
 
 
 
 
Estimated Future Payouts under Non-Equity Incentive Plan Awards (1)
 
Estimated Future Payouts under Equity Incentive Plan Awards (2)
 
Grant Date Fair Value of LTIP Awards ($)(3)
Name
 
Grant Date
 
Threshold ($)
 
Target
($)
 
Maximum
($)
 
Threshold (#)
 
Target (#)
 
Maximum (#)
 
Robert E. Rasmus 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Short-term incentive plan
 
N/A
 
416,667

 
833,334

 
1,250,000

 

 

 

 

June 2014 PPU
 
6/23/2014
 

 

 

 
8,322

 
16,644

 
33,288

 
1,156,924

STI PPU
 
2/13/2015
 

 

 

 
15,375

 
30,750

 
61,500

 
1,150,665

James M. Whipkey 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Short-term incentive plan
 
N/A
 
416,667

 
833,334

 
1,250,000

 

 

 

 

June 2014 PPU
 
6/23/2014
 

 

 

 
8,322

 
16,644

 
33,288

 
1,156,924

STI PPU
 
2/13/2015
 

 

 

 
15,375

 
30,750

 
61,500

 
1,150,665

Laura C. Fulton 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Short-term incentive plan
 
N/A
 
125,000

 
250,000

 
500,000

 

 

 

 

June 2014 PPU
 
6/23/2014
 

 

 

 
3,495

 
6,991

 
13,982

 
363,182

Jefferies V. Alston, III 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Short-term incentive plan
 
N/A
 
416,667

 
833,334

 
1,250,000

 

 

 

 

June 2014 PPU
 
6/23/2014
 

 

 

 
8,322

 
16,644

 
33,288

 
1,156,924

STI PPU
 
2/13/2015
 

 

 

 
15,375

 
30,750

 
61,500

 
1,150,665

Mark C. Skolos 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Short-term incentive plan
 
N/A
 
103,750

 
207,500

 
415,000

 

 

 

 

June 2014 PPU
 
6/23/2014
 

 

 

 
2,497

 
4,994

 
9,988

 
259,438

Chad M. McEver 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Short-term incentive plan
 
N/A
 
43,000

 
86,000

 
172,000

 

 

 

 

(1)
Amounts shown represent amounts under the STI. If minimum levels of performance are not met, then the payout for one or more of the components of the STI may be zero. See “-Compensation Discussion and Analysis-Components of Executive Compensation-Annual Short-Term Cash Incentive” above for further discussion of these awards.
(2)
The number of units shown represent units awarded under the LTIP. The PPUs awarded in June 2014 will vest in their entirety on December 31, 2016 if the specified performance conditions are satisfied. The PPUs awarded on February 13, 2015 will vest in their entirety on December 31, 2017 if the specified performance conditions are satisfied. If minimum levels of performance are not met, then none of the PPUs will vest. See “-Compensation Discussion and Analysis-Components of Executive Compensation-Long-Term Incentive Compensation” above for further discussion of these awards.
(3)
Equity award amounts reflect the aggregate grant date fair value of LTIP awards granted for the periods presented, computed in accordance with FASB ASC Topic 718. See Note 12 to our consolidated financial statements for additional assumptions underlying the value of the equity awards.
Narrative Disclosure to the Summary Compensation Table and Grants of the Plan-Based Awards Table
A description of material factors necessary to understand the information disclosed in the tables above with respect to salaries, bonuses, equity awards, non-equity incentive plan compensation, and 401(k) plan contributions can be found in the compensation discussion and analysis that precedes these tables.

101


Outstanding Equity Awards at Fiscal Year-End
The following are the outstanding equity awards for the named executive officers as of December 31, 2014:
 
 
Outstanding LTIP Awards
Name and Principal Position
 
Equity Incentive Plan Awards: Unearned Units That Have Not Vested (1)
 
Equity Incentive Plan Awards: Market Value of Unearned Units That Have Not Vested ($) (1)(2)
Robert E. Rasmus, Co-Chief Executive Officer (3)
 
16,644

 
516,463

James M. Whipkey, Co-Chief Executive Officer (3)
 
16,644

 
516,463

Laura C. Fulton, Chief Financial Officer
 
6,991

 
216,931

Jefferies V. Alston, III, Chief Operating Officer (3)
 
16,644

 
516,463

Mark C. Skolos, General Counsel and Secretary
 
4,994

 
154,964

Chad M. McEver, Vice President
 

 

(1)    The PPUs were awarded in June 2014, and vest in their entirety over a range of 0% to 200% on December 31, 2016, if the specified performance conditions are satisfied. To determine the number of unearned units and the market value of such units, the calculation of the number of PPUs granted that are expected to vest is based on assumed performance of 100%.
(2)     Value calculated based on the closing price at December 31, 2014 of our common units at $31.03.
(3)     On February 13, 2015, Messrs. Rasmus, Whipkey and Alston each received 30,750 PPUs under the LTIP for amounts earned in 2014 under the STI.  The PPUs vest in their entirety over a range of 0% to 200% on December 31, 2017 if the specified performance conditions are satisfied.  The PPUs awarded on February 13, 2015 to Messrs. Rasmus, Whipkey and Alston are not reflected in the table above. Please see “Compensation Discussion and Analysis-Annual Short-Term Cash Incentive” and “Compensation Discussion and Analysis-Long-Term Incentive Compensation” for more information about the STI award and the PPUs.
Option Exercises and Units Vested
No unit awards to the named executive officers vested during 2014.
Pension Benefits
Currently, our general partner does not, and does not intend to, provide pension benefits to our named executive officers. Our general partner may change this policy in the future.
Nonqualified Deferred Compensation
Currently, our general partner does not, and does not intend to, sponsor or adopt a nonqualified deferred compensation plan. Our general partner may change this policy in the future.
Potential Payments Upon Termination or a Change in Control
Aggregate Payments. The table below reflects the aggregate amount of payments and benefits that we believe our named executive officers would have received under their employment agreement and the Partnership’s LTIP upon certain specified termination of employment and/or a change in control events, in each case, had such event occurred on December 31, 2014. Details regarding individual plans and arrangements follow the table. The amounts below constitute estimates of the amounts that would be paid to our named executive officers upon each designated event, and do not include any amounts accrued through fiscal 2014 year-end that would be paid in the normal course of continued employment, such as accrued but unpaid salary and benefits generally available to all salaried employees. The actual amounts to be paid are dependent on various factors, which may or may not exist at the time a named executive officer is actually terminated and/or a change in control actually occurs. Therefore, such amounts and disclosures should be considered “forward-looking statements.”
Name and Principal Position
 
Change in Control ($)
 
Termination without Cause or by Executive for Good Reason ($)
 
Termination with Cause or for Death or Disability ($)
 
Termination Due to Expiration of Term ($)
Robert E. Rasmus, Co-Chief Executive Officer
 
516,463

 
750,000

 

 

James M. Whipkey, Co-Chief Executive Officer
 
516,463

 
750,000

 

 

Laura C. Fulton, Chief Financial Officer
 
216,931

 
150,000

 

 
150,000

Jefferies V. Alston, III, Chief Operating Officer
 
516,463

 
750,000

 

 

Mark C. Skolos, General Counsel and Secretary
 
154,964

 
125,000

 

 
125,000

Chad M. McEver, Vice President
 

 

 

 


102


Employment Agreements. Other than Mr. McEver, each of our named executive officers has entered into an employment agreement with our sponsor. The initial term of the each employment agreement is one year from the effective date of such agreement, with automatic extensions for additional one-year periods unless either party provides at least sixty days’ advance written notice of the intent to terminate the agreement.
The employment agreements contain severance provisions. Under the terms of the employment agreements, the employment of the named executive officer may be terminated by our sponsor with or without Cause (defined below), by the named executive officer for or without Good Reason (defined below), due to the named executive officer’s disability or death, or due to expiration of the term of the employment agreement.
Upon a termination by our sponsor for Cause, by the named executive officer without Good Reason, due to the named executive officer’s disability or death, or with respect to Mr. Rasmus, Mr. Whipkey and Mr. Alston due to expiration of the term of the employment agreement, the named executive officer is entitled to the following severance benefits: (i) payment of all accrued and unpaid base salary through the date of termination, (ii) reimbursement for all incurred but unreimbursed expenses entitled to reimbursement, and (iii) provision of any benefits to which the named executive officer is entitled pursuant to the terms of any applicable benefit plan or program (collectively, the “Accrued Obligations”). Under Ms. Fulton’s and Mr. Skolos’ employment agreement, upon a termination due to the expiration of the term, Ms. Fulton and Mr. Skolos shall be entitled to the following severance benefits: (i) payment of the Accrued Obligations and (ii) 50% of such named executive officer’s base salary, payable over the remainder of the term of the employment agreement in installments substantially similar to our sponsor’s salary payment practices.
Upon a termination by our sponsor without Cause or by the named executive officer for Good Reason, the named executive officer is entitled to the following severance benefits: (i) payment of the Accrued Obligations and (ii) (A) in the case of Mr. Rasmus, Mr. Whipkey and Mr. Alston, payment of an amount equal to $750,000 in a lump sum payment on the date that is 30 days after the date of termination and (B) in the case of Ms. Fulton and Mr. Skolos, the remainder of such employee’s base salary for the remaining term of the employment agreement, which in no event shall be less than 50% of such base salary, payable over the remainder of the term of the employment agreement in installments substantially similar to our sponsor’s salary payment practices. Payment of the additional lump sum payment is contingent upon the named executive officer’s execution and non-revocation of a general release of claims in favor of us. No named executive officer has any right to receive a “gross up” for any excise tax imposed by Section 4999 of the Code, or any federal, state or local income tax.
Under the employment agreements, the following terms generally have the meanings set forth below:
Cause means a named executive officer’s (i) conviction of, or entry of a guilty plea or plea of no contest with respect to, a felony or any other crime directly or indirectly involving the named executive officer’s lack of honesty or moral turpitude, (ii) drug or alcohol abuse for which the named executive officer fails to undertake and maintain treatment within five calendar days after requested by our sponsor, (iii) acts of fraud, embezzlement, theft, dishonesty or gross misconduct, (iv) material misappropriation (or attempted misappropriation) of any of our funds or property, or (v) a breach of the named executive officer’s obligations described under the employment agreement, as determined by a majority of our sponsor’s board of directors.
Good Reason means, without the named executive officer’s consent: (i) a material breach by our sponsor of its obligations under the employment agreement, (ii) any material diminution of the duties of the named executive officer, (iii) a reduction in the named executive officer’s base salary, other than pursuant to a proportionate reduction applicable to all senior executives or employees generally and the members of our sponsor’s board of directors, to the extent such board members receive board fees, or (iv) the relocation of the geographic location of the named executive officer’s principal place of employment by more than 50 miles.
The following table reflects payments that would have been made under the named executive officer’s employment agreement in the event the named executive officer’s employment was terminated as of December 31, 2014.
Name and Principal Position
 
Termination without Cause or by Executive for Good Reason ($)
 
Termination with Cause or for Death or Disability ($)
 
Termination Due to Expiration of Term ($)
Robert E. Rasmus, Co-Chief Executive Officer
 
750,000

 

 

James M. Whipkey, Co-Chief Executive Officer
 
750,000

 

 

Laura C. Fulton, Chief Financial Officer
 
150,000

 

 
150,000

Jefferies V. Alston, III, Chief Operating Officer
 
750,000

 

 

Mark C. Skolos, General Counsel and Secretary
 
125,000

 

 
125,000

Chad M. McEver, Vice President
 

 

 

2014 Performance Phantom Unit Grants under the LTIP. Other than Mr. McEver, each of our named executive officers held outstanding performance phantom limited partner units, or PPUs, under our form of phantom unit award agreement (performance based vesting) (the “PPU Award Agreement”) and the LTIP as of December 31, 2014. If a Change in Control occurs and the named executive officer has remained continuously employed by us from the date of grant to the date upon which such Change in Control occurs, then the phantom units granted to the named executive officer under the PPU Award Agreement and related distribution equivalent rights will fully vest on the date upon which such Change in Control occurs.



103


The following terms generally have the following meanings for purposes of the LTIP and PPU Award Agreement:
Affiliate means, with respect to any person, any other person that directly or indirectly through one or more intermediaries controls, is controlled by or is under common control with, the person in question. As used herein, the term “control” means the possession, direct or indirect, of the power to direct or cause the direction of the management and policies of a person, whether through ownership of voting securities, by contract or otherwise.
Change of Control means, and shall be deemed to have occurred upon one or more of the following events: (i) any “person” or “group” within the meaning of those terms as used in Sections 13(d) and 14(d)(2) of the Exchange Act, other than members of the general partner, the Partnership, or an Affiliate of either the general partner or the Partnership, shall become the beneficial owner, by way of merger, consolidation, recapitalization, reorganization or otherwise, of 50% or more of the voting power of the voting securities of the general partner, (ii) the limited partners of the general partner or the Partnership approve, in one transaction or a series of transactions, a plan of complete liquidation of the general partner or the Partnership, (iii) the sale or other disposition by either the general partner or the Partnership of all or substantially all of its assets in one or more transactions to any Person other than an Affiliate, or (iv) the general partner or an Affiliate of the general partner or the Partnership ceases to be the general partner of the Partnership;
The following table reflects amounts that would have been received by each of the named executive officers under the LTIP and related PPUs in the event there was a Change in Control as of December 31, 2014. The amounts reported below assume that the price per unit of our common units was $31.03, which was the closing price per unit of our common stock on December 31, 2014.
Name and Principal Position
 
Change in Control ($) (1)(2)
Robert E. Rasmus, Co-Chief Executive Officer
 
516,463

James M. Whipkey, Co-Chief Executive Officer
 
516,463

Laura C. Fulton, Chief Financial Officer
 
216,931

Jefferies V. Alston, III, Chief Operating Officer
 
516,463

Mark C. Skolos, General Counsel and Secretary
 
154,964

Chad M. McEver, Vice President
 

(1)
Amounts reported relate to the PPUs granted on June 23, 2014 and vest in their entirety over a range of 0% to 200% on December 31, 2016, if the specified performance conditions are satisfied. To determine the number of unearned units and the market value of such units, the calculation of the number of PPUs granted on June 23, 2014 that are expected to vest is based on assumed performance of 100%.
(2)
The table above does not reflect any amounts attributable to the PPUs granted to Messrs. Rasmus, Whipkey and Alston on February 13, 2015 under the LTIP for awards earned in 2014 under the STI.  Please see “Compensation Discussion and Analysis-Annual Short-Term Cash Incentive” and “Compensation Discussion and Analysis-Long-Term Incentive Compensation” for more information about the STI award and the PPUs.
Director Compensation
The executive officers of our general partner who also serve as directors of our general partner do not receive additional compensation for their services as a director of our general partner. The table below sets forth the annual compensation earned during 2014 by the non-executive directors of our general partner.
Director
 
Fees Earned or Paid in Cash ($)
 
Unit Awards ($)
 
Total ($)
John F. Affleck-Graves
 
70,000

 
50,000

 
120,000

Robert L. Cabes, Jr. (1)
 

 

 

Gregory F. Evans (2)
 

 

 

John R. Huff
 
50,000

 
50,000

 
100,000

John Kevin Poorman
 
70,000

 
50,000

 
120,000

Trevor M. Turbidy
 

 

 

Steven A. Webster (3)
 

 

 

R. Graham Whaling (4)
 

 

 

Joseph C. Winkler III
 
100,000

 
50,000

 
150,000

(1) Mr. Cabes resigned as a director of our general partner on February 14, 2014.
(2) Mr. Evans was appointed as a director of our general partner on February 17, 2014.
(3) Mr. Webster resigned as a director of our general partner on February 17, 2015.
(4) Mr. Whaling was appointed as a director of our general partner on February 17, 2015.



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Following the IPO on August 16, 2012, each independent director of our general partner receives an annual retainer of $50,000. Each January, our independent directors also receive an annual grant of the number of common units having a grant date fair value of approximately $50,000 as of such date. Such units are not subject to a vesting period. Further, each independent director serving as a chairman or a member of a committee of the board of directors of our general partner will receive an annual retainer of $25,000 or $10,000, respectively.
The Partnership granted $100,000, $200,000 and $200,000 of equity awards to its directors during 2013, 2014 and 2015, respectively.
Compensation Committee Interlocks and Insider Participation
None of the directors or executive officers of our general partner served as members of the compensation committee or board of directors of another entity that has or had an executive officer who served as a member of the board of directors of our general partner during 2014. Our general partner’s board of directors is not required to maintain, and does not maintain, a compensation committee. In addition, as previously noted, other than for equity-based awards under our LTIP, we do not directly employ or compensate the executive officers of our general partner. Rather, under the Services Agreement, we reimburse Hi-Crush Services and its affiliates for, among other things, the allocable expenses incurred in compensating our general partner’s executive officers. Messrs. Rasmus, Whipkey and Alston, who are members of the board of directors of our general partner, are also executive officers of our general partner.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS
The following table sets forth the beneficial ownership of our common and subordinated units issued and outstanding as of February 27, 2015 for:
our general partner;
beneficial owners of 5% or more of our common and subordinated units;
each director and named executive officer of our general partner; and
all of our general partner's directors and executive officers as a group.
 
Common Units Beneficially Owned
 
Percentage of Common Units Beneficially Owned
 
Subordinated Units Beneficially Owned
 
Percentage of Subordinated Units Beneficially Owned
 
Percentage of Common and Subordinated Units Beneficially Owned
Hi-Crush Proppants LLC (1)(2)

 
%
 
13,640,351

 
100
%
 
36.91
%
Hi-Crush GP LLC (2)

 

 

 

 

Robert E. Rasmus (2)(4)
30,600

 
*

 

 

 
*

James M. Whipkey (2)
100

 
*

 

 

 
*

Jefferies V. Alston, III (2)

 

 

 

 

Laura C. Fulton(2)
11,000

 
*

 

 

 
*

Mark C. Skolos (2)

 

 

 

 

Chad M. McEver (2)

 

 

 

 

John F. Affleck-Graves(2)
5,730

 
*

 

 

 
*

Gregory F. Evans (3)

 

 

 

 

John R. Huff (2)
152,969

 
*

 

 

 
*

John Kevin Poorman (2)
2,969

 
*

 

 

 
*

Trevor M. Turbidy (3)

 

 

 

 

R. Graham Whaling (3)

 

 

 

 

Joseph C. Winkler III (2)
5,730

 
*

 

 

 
*

All executive officers and directors as a group (14 persons)
1,330,893

 
5.71%

 

 

 
3.60%

*
 Less than one percent
(1)
Avista Capital Partners II, LP, Avista Capital Partners (Offshore) II-A, LP and Avista Capital Partners (Offshore) II, LP indirectly own 58% of the membership interests of Hi-Crush Proppants LLC, through two investment vehicles, ACP HIP Splitter, LP and ACP HIP Splitter (Offshore), LP. Each of Avista Capital Partners II, LP, Avista Capital Partners (Offshore) II-A, LP and Avista Capital Partners (Offshore) II, LP is controlled by its general partner, Avista Capital Partners II GP, LLC (“Avista GP”). Voting and investment determinations are made by an investment committee of Avista GP, comprised of the following members: Thompson Dean, Steven Webster, David Burgstahler, David Durkin, Brendan Scollans and Sriram Venkataraman. As a result, and by virtue of the relationships described above, each of Thompson Dean, Steven Webster, David Burgstahler, David Durkin, Brendan Scollans and Sriram Venkataraman may be deemed to exercise voting and dispositive power with respect to securities held by ACP HIP Splitter, LP and ACP HIP Splitter (Offshore), LP. The address for Avista Capital Partners is 65 East 55th Street, 18th Floor, New York, NY 10022.
(2)
The address for each of Hi-Crush Proppants LLC, Hi-Crush GP LLC, Robert E. Rasmus, James M. Whipkey, Jefferies V. Alston, III, Laura C. Fulton, Mark C. Skolos, Chad M. McEver, William H. Fehr, John R. Huff, John F. Affleck-Graves, Joseph C. Winkler III and John Kevin Poorman is Three Riverway, Suite 1550, Houston, Texas 77056.
(3)
The address for each of Gregory F. Evans, Trevor M. Turbidy and R. Graham Whaling is 1000 Louisiana St., Suite 3700, Houston, Texas 77002.
(4)
Includes 500 common units owned by the reporting person’s son. Mr. Rasmus disclaims beneficial ownership of the 500 common units held by his son.

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Equity Compensation Plan Information
The following table sets forth information as of December 31, 2014 with respect to compensation plans under which our equity securities are authorized for issuance.
 
(a) Number of  Units to be Issued Upon Exercise of Outstanding Unit Options and Rights (2)
 
(b) Weighted  Average Exercise Price Of Outstanding Unit Options and Rights
 
(c) Number of  Units Remaining Available For Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column (a)) (3)
Plan Category
 
 
 
 
 
Equity compensation plans approved by unitholders
 
 
 
 
 
N/A

 

 

Equity compensation plans not approved by unitholders:
 
 
 
 
 
Long-Term Incentive Plan (1)
81,017

 

 
1,265,241

Total for equity compensation plans
81,017

 

 
1,265,241

(1) The Partnership’s Long-Term Incentive Plan (“LTIP”) was adopted by our general partner in August 2012 in connection with our IPO. The LTIP contemplates the issuance or delivery of up to 1,364,035 common units to satisfy awards under the plan.
(2) Represents phantom units subject to equity-settled time-based unit awards and performance unit awards granted under the LTIP, assuming the target distribution at the time of vesting. Payment with respect to the outstanding equity-settled performance unit awards range from 0% to 200% of the target distribution depending on performance actually attained, with a maximum number of 145,431 units shown in column (a) being potentially issuable under the LTIP. There is no exercise price applicable to these awards.
(3) Includes units that may be issued in payment of the outstanding equity-settled performance phantom unit awards reported in column (a) if and to the extent such payment exceeds the target distribution amount reported in column (a) with respect to such awards.
On January 8, 2015, the Partnership issued 6,344 common units to directors. On February 13, 2015, the Partnership awarded 92,250 equity-settled performance phantom unit awards to our Co-Chief Executive Officers and Chief Operating Officer under the STI. Please see "Item 11, "Executive Compensation - Compensation Discussion and Analysis - Components of Executive Compensation - Annual Short Term Cash Incentive" for more additional information regarding the PPUs. The units awarded after December 31, 2014 are not included in the Equity Compensation Plan Information table above, which provides information as of December 31, 2014.


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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE (Dollars in thousands)
As of February 27, 2015, our sponsor owned 13,640,351 subordinated units, representing an aggregate 36.9% limited partner interest in us, owned the incentive distribution rights and owned and controlled our general partner. Our sponsor also appoints all of the directors of our general partner, which maintains a non-economic general partner interest in us.
Certain of the transactions and agreements disclosed in this section were determined by and among affiliated entities and, consequently, the terms of such transactions and agreements are not the result of arm’s length negotiations. These terms are not necessarily at least as favorable to the parties to these transactions and agreements as the terms that could have been obtained from unaffiliated third parties.
Distributions and Payments to Affiliates of our General Partner
The following summarizes the distributions and payments made or to be made by us to our general partner and its affiliates in connection with the formation, ongoing operation and any liquidation of Hi-Crush Partners LP.
Formation Stage
The aggregate consideration received by affiliates of our general partner for the contribution of their interests:
13,640,351 common units including 12,937,500 common units Hi-Crush Proppants LLC, as the selling unitholder, sold to the public in our IPO;
13,640,351 subordinated units; and
our incentive distribution rights.
Operational Stage
Distributions of cash available for distribution to our general partner and its affiliates:
We will generally make cash distributions 100% to our unitholders, including affiliates of our general partner. In addition, if distributions exceed the minimum quarterly distribution and other higher target distribution levels, our sponsor (as the holder of our incentive distribution rights) will be entitled to increasing percentages of the distributions, up to 50.0% of the distributions above the highest target distribution level.
Assuming we have sufficient cash available for distribution to pay the full minimum quarterly distribution on all of our outstanding common units and subordinated units for four quarters and that we pay such minimum quarterly distribution, affiliates of our general partner would receive an annual distribution of $25,917 on their units.
Payments to our general partner and its affiliates:
Our general partner does not receive a management fee or other compensation for its management of our partnership, but we reimburse our general partner and its affiliates for all direct and indirect expenses they incur and payments they make on our behalf. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us.
Withdrawal or removal of our general partner:
If our general partner withdraws or is removed, its non-economic general partner interest and our sponsor’s incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests.
Liquidation Stage
Upon our liquidation, the partners will be entitled to receive liquidating distributions according to their particular capital account balances.






108


Agreements with Affiliates in connection with our Initial Public Offering
In connection with our IPO on August 16, 2012, we entered into certain agreements with our sponsor, as described in more detail below.
Contribution Agreement
We entered into a contribution agreement that affected the transactions, including the transfer of the ownership interests in Hi-Crush Chambers LLC, Hi-Crush Railroad LLC, Hi-Crush Wyeville LLC and Hi-Crush Operating LLC and the issuance by us to our sponsor of common units, subordinated units and incentive distribution rights. While we believe this agreement is on terms no less favorable to any party than those that could have been negotiated with an unaffiliated third party, it was not the result of arm’s-length negotiations. All of the transaction expenses incurred in connection with these transactions were paid by our sponsor from the proceeds of the IPO.
Omnibus Agreement
We entered into an omnibus agreement with affiliates of our general partner, including our sponsor, which addresses certain aspects of our relationship with them, including:
our use of the name “Hi-Crush” and related marks;
our payment of administrative services fees to our sponsor for general and administrative services;
the assumption by our sponsor of one of our customer contracts beginning on May 1, 2013 (our sponsor waived its right to require us to assign to the sponsor the customer contract); and
certain indemnification obligations.
The omnibus agreement can be amended by written agreement of all parties to the agreement. However, we may not agree to any amendment or modification that would, in the reasonable discretion of our general partner, be adverse in any material respect to the holders of our common units without prior approval of the conflicts committee. So long as our sponsor controls our general partner, the omnibus agreement will remain in full force and effect unless mutually terminated by the parties. If our sponsor ceases to control our general partner, the omnibus agreement will terminate.
Registration Rights Agreement
In connection with our IPO on August 16, 2012, we entered into a registration rights agreement with our sponsor, pursuant to which we may be required to register the sale of the (i) common units issued (or issuable) to our sponsor pursuant to the contribution agreement, (ii) subordinated units and (iii) common units issuable upon conversion of the subordinated units or the Combined Interests (as defined in our partnership agreement) pursuant to the terms of the partnership agreement (together, the “Registrable Securities”) it holds. Under the registration rights agreement, our sponsor will have the right to request that we register the sale of Registrable Securities held by it, and our sponsor will have the right to require us to make available shelf registration statements permitting sales of Registrable Securities into the market from time to time over an extended period, subject to certain limitations. The registration rights agreement also includes provisions dealing with indemnification and contribution and allocation of expenses. All of our Registrable Securities held by our sponsor and any permitted transferee will be entitled to these registration rights.
Services Agreements
Effective August 16, 2012, we entered into the Services Agreement by and among our general partner, Hi-Crush Services, a wholly-owned subsidiary of the sponsor, and the Partnership, pursuant to which Hi-Crush Services provides certain management and administrative services to our general partner to assist in operating our business. Under the Services Agreement, the Partnership reimburses Hi-Crush Services and its affiliates, on a monthly basis, for the allocable expenses it incurs in its performance under the Services Agreement. These expenses include, among other things, salary, bonus, incentive compensation, rent and other administrative expense for individuals and entities that perform services for us or on our behalf. Hi-Crush Services and its affiliates are not liable to us for its performance of services under the Services Agreement except a liability resulting from gross negligence.
Agreements with Affiliates in connection with our Acquisition of Hi-Crush Augusta LLC

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, which is located in Eau Claire County, Wisconsin, for $37,500 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, 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.  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.

109


On April 8, 2014, we 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 closed on April 28, 2014, and at closing, our preferred equity interest in Augusta was converted into common equity interests of Augusta.  Following the Augusta Contribution, we own 98.0% of Augusta’s common equity interests.
Other Transactions with Related Persons
On May 25, 2011, our sponsor entered into a management services agreement with Red Oak Capital Management LLC (the “Service Provider”), which is owned by two members who are also equity members in our sponsor. The agreement provides for certain management and administrative support services to be provided to our sponsor for a term of one year and that thereafter remains in place upon the same terms and conditions. Either party may terminate the agreement by delivering written notice within 90 days prior to the date of expiration of the initial term or any time after the expiration of the initial term, by delivering written notice 90 days prior to the desired date of termination. Our sponsor reimburses the Service Provider 95% of the Service Provider’s actual costs limited to $850 per year. Total fees were $166 during the period from August 16 through December 31, 2012 and $318 for the period from January 1 through August 15, 2012. These fees are included in general and administrative expenses. Management fees incurred during the years ended December 31, 2014 and 2013 are included as a portion of the management services expense from Hi-Crush Services, as discussed below.
Our sponsor paid quarterly director fees to non-management directors that may be members and/or holders of our sponsor’s debt through the date of the IPO. Total fees were $62 for the period from January 1 through August 15, 2012.
During the years ended December 31, 2014 and 2013 and the period from August 16 through December 31, 2012, the Partnership incurred $9,421, $5,122 and $1,702, respectively, of management service expenses from Hi-Crush Services.
In the normal course of business, our sponsor and its affiliates, including Hi-Crush Services, and the Partnership may from time to time make payments on behalf of each other. During the period from August 16 through December 31, 2012, we made payments of $9,866 to various suppliers, vendors or other counterparties on behalf of our sponsor. This balance was offset by $1,028 of management fees charged by our sponsor and $3,223 of net payments made by our sponsor on behalf of us. The balance of $5,615 was repaid by our sponsor in February 2013.
During the year ended December 31, 2014, the Partnership purchased $1,385 of sand from Goose Landing, LLC, a wholly owned subsidiary of Northern Frac Proppants II, LLC. The father of Mr. Alston, who is our general partner's Chief Operating Officer, owns a controlling equity interest in Northern Frac Proppants II, LLC. Although we acquired the sand at a purchase price in excess of our production cost per ton, the terms of the purchase price were the result of arm's length negotiations.
As of December 31, 2014 and 2013, an outstanding balance of $13,459 and $10,352, respectively, payable to our sponsor is maintained as a current liability under the caption “Due to sponsor”. In connection with the acquisition of the preferred interest in Augusta, on January 31, 2013, our sponsor extinguished balances owed by Augusta as follows:
Conversion into common units of Hi-Crush Augusta LLC, representing a non-controlling interest in the Partnership
$
38,172

Conversion into preferred units of Hi-Crush Augusta LLC
9,543

Assumption of bank debt
33,250

Total payable to sponsor extinguished
$
80,965

Procedures for Review, Approval and Ratification of Transactions with Related Persons
The board of directors of our general partner has adopted policies for the review, approval and ratification of transactions with related persons and a written Code of Business Conduct and Ethics. Under our code of business conduct and ethics, a director is required to bring to the attention of the chief executive officer(s) or the board any conflict or potential conflict of interest that may arise between the director or any affiliate of the director, on the one hand, and us or our general partner on the other. The resolution of any such conflict or potential conflict should, at the discretion of the board in light of the circumstances, be determined by a majority of the disinterested directors. In determining whether to approve or ratify a transaction with a related party, the board of directors of our general partner will take into account, among other factors it deems appropriate, (1) whether the transaction is on terms no less favorable than terms generally available to an unaffiliated third party under the same or similar circumstances, (2) the extent of the related person’s interest in the transaction and (3) whether the interested transaction is material to the Partnership. Our partnership agreement contains detailed provisions regarding the resolution of conflicts of interest, as well as the standard of care the board of directors of our general partner must satisfy in doing so.


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If a conflict or potential conflict of interest arises between our general partner or its affiliates, on the one hand, and us or our unitholders, on the other hand, the resolution of any such conflict or potential conflict will be addressed by the board of directors of our general partner in accordance with the provisions of our partnership agreement. Such a conflict of interest may arise, for example, in connection with negotiating and approving the acquisition of any assets from our sponsor. At the discretion of the board in light of the circumstances, the resolution may be determined by the board in its entirety or by the conflicts committee meeting the definitional requirements for such a committee under our partnership agreement. We do not expect that our code of business conduct and ethics or any policies that the board of directors of our general partner will adopt will require the approval of any transactions with related persons, including our sponsor, by our unitholders.
We expect to have the opportunity to acquire additional assets from our sponsor in the future. Our sponsor or other affiliates of our general partner are free to offer properties to us on terms they deem acceptable. Under our code of business conduct and ethics, the board of directors of our general partner (or the conflicts committee, if the board of directors delegates the necessary authority to the conflicts committee) will be free to accept or reject any such offers and to negotiate any terms it deems acceptable to us and that the board of directors of our general partner or the conflicts committee will decide the appropriate value of any assets offered to us by affiliates of our general partner. In making such determination of value, the board of directors of our general partner or the conflicts committee are permitted to consider any factors they determine in good faith to consider. The board of directors or the conflicts committee will consider a number of factors in its determination of value, including, without limitation, operating data, reserve information, operating cost structure, current and projected cash flow, financing costs, the anticipated impact on distributions to our unitholders, the price outlook for frac sand, reserve life and the location and quality of the reserves.
Based on our code of business conduct and ethics, any executive officer is required to avoid conflicts of interest unless approved by the board of directors of our general partner.
In the case of any sale of equity by us in which an owner or affiliate of an owner of our general partner participates, our practice is to obtain approval of the board for the transaction. The board will typically delegate authority to set the specific terms to a pricing committee, consisting of one of the co-chief executive officers and one independent director. Actions by the pricing committee require unanimous approval.


111


ITEM 14.  PRINCIPAL ACCOUNTING FEES AND SERVICES
Our general partner is responsible for the Partnership’s internal controls and the financial reporting process. The independent registered public accounting firm, PricewaterhouseCoopers LLP (“PwC”), is responsible for performing independent audits of the Partnership’s consolidated financial statements and issuing an opinion on the conformity of those audited financial statements with United States generally accepted accounting principles. The audit committee monitors the Partnership’s financial reporting process and reports to the board of directors of our general partner on its findings.
Prior to us becoming a public company, in 2012 our sponsor selected and engaged PwC as its independent registered public accounting firm to audit the consolidated financial statements of our sponsor for the fiscal years ending December 31, 2011 and 2010. The audit committee of the board of directors of our general partner selected and engaged PwC to audit our consolidated financial statements for the years ended December 31, 2014, 2013 and 2012.
In connection with our IPO and the formation of our audit committee, the board of directors of our general partner adopted a policy for pre-approving the services and associated fees of the our independent registered public accounting firm. Under this policy, the audit committee must pre-approve all services and associated fees provided to us by its independent registered public accounting firm, with certain exceptions described in the policy.
All PwC services and fees in each of the three years ended December 31, 2014 were pre-approved by our sponsor or the board of directors of our general partner, as applicable.
The following table presents fees billed or expected to be billed for professional audit services and other services rendered to the Partnership by PwC for the periods ended December 31, 2014, 2013 and 2012 (in thousands).
 
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  
 
Successor
 
Successor
 
Successor
 
Predecessor
Audit Fees
$
665

 
$
504

 
$
401

 
$
231

All Other Fees (1)
48

 
127

 
144

 
131

Audit-Related Fees (2)
92

 

 
78

 
167

Tax Fees (3)
312

 
262

 

 
62

Total Fees paid to PwC
$
1,117

 
$
893

 
$
623

 
$
591

(1) Represents fees related to tax compliance and consulting.
(2) Represents fees related to offering documents.
(3) Represents fees related to tax return preparation.
The audit committee has established procedures for engagement of PwC to perform services other than audit, review and attest services. In order to safeguard the independence of PwC, for each engagement to perform such non-audit service, (a) management and PwC affirm to the audit committee that the proposed non-audit service is not prohibited by applicable laws, rules or regulations; (b) management describes the reasons for hiring PwC to perform the services; and (c) PwC affirms to the audit committee that it is qualified to perform the services. The audit committee has delegated to its chair its authority to pre-approve such services in limited circumstances, and any such pre-approvals are reported to the audit committee at its next regular meeting. All services provided by PwC in 2014 were audit-related or tax and are permissible under applicable laws, rules and regulations and were pre-approved by the board of directors of our general partner in accordance with its procedures. In 2014, the board of directors of our general partner considered the amount of non-audit services provided by PwC in assessing its independence.


112


PART IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(a)(1) Financial Statements
Our Consolidated and Pro Forma Financial Statements are included under Part II, Item 8 of this Annual Report on Form 10-K. For a listing of these statements and accompanying footnotes, please read “Index to Financial Statements” on page F-1 of this Annual Report.
(a)(2) Financial Statement Schedules
All schedules have been omitted because they are either not applicable, not required or the information called for therein appears in the consolidated financial statements or notes thereto.
(a)(3) Exhibits
The following documents are filed as a part of this Annual Report on Form 10-K or incorporated by reference:
Exhibit  Number        
 
Description
2.1***
 
Membership Interest Purchase Agreement, dated May 13, 2013, by and among the Partnership, the members of D & I Silica, LLC, and their respective owners (incorporated by reference to Exhibit 1.01 to the Registrant’s Current Report on Form 8-K, filed with the SEC on May 16, 2013).
3.1
 
Certificate of Limited Partnership of Hi-Crush Partners LP (incorporated by reference to Exhibit 3.1 to the Registrant's Registration Statement on Form S-1, Registration No. 333-182574, filed with the SEC on July 9, 2012).
3.2
 
Second Amended and Restated Agreement of Limited Partnership of Hi-Crush Partners LP, dated January 31, 2013 (incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K, filed with the SEC on February 5, 2013).
4.1
 
Registration Rights Agreement by and between Hi-Crush Partners LP and Hi-Crush Proppants LLC dated August 20, 2012 (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K, filed with the SEC on August 21, 2012).
4.2
 
First Amendment to Registration Rights Agreement by and between Hi-Crush Partners LP and Hi-Crush Proppants LLC, dated January 31, 2013 (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K, filed with the SEC on February 5, 2013).
10.1
 
Amended and Restated Credit Agreement, dated April 28, 2014, among Hi-Crush Partners LP, as borrower, Amegy Bank National Association, as administrative agent, issuing lender and swing line lender, Barclays Bank PLC and Morgan Stanley Senior Funding, Inc., as co-documentation agents, IberiaBank, as syndication agent, and the lenders named therein (incorporated by reference to Exhibit 10.2 to the Registrant’s Quarterly Report on Form 10-Q, filed with the SEC on August 5, 2014).
10.2
 
Credit Agreement, dated April 28, 2014, among Hi-Crush Partners LP, as borrower, Morgan Stanley Senior Funding, Inc., as administrative agent and collateral agent, Barclays Bank PLC, as syndication agent, and the lenders named therein (incorporated by reference to Exhibit 10.3 to the Registrant’s Quarterly Report on Form 10-Q, filed with the SEC on August 5, 2014).
10.3
 
Management Services Agreement dated effective August 16, 2012, among Hi-Crush Partners LP, Hi-Crush GP LLC and Hi-Crush Services LLC (incorporated by reference to Exhibit 10.2 to the Registrant’s Quarterly Report on Form 10-Q, filed with the SEC on November 11, 2012).
10.4
 
Maintenance and Capital Spare Parts Agreement dated effective August 16, 2012, among Hi-Crush Partners LP, Hi-Crush GP LLC and Hi-Crush Proppants LLC (incorporated by reference to Exhibit 10.3 to the Registrant’s Quarterly Report on Form 10-Q, filed with the SEC on November 11, 2012).
10.5
 
Contribution, Assignment and Assumption Agreement by and among Hi-Crush Partners LP, Hi-Crush GP LLC and Hi-Crush Proppants LLC, dated August 15, 2012 (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K, filed with the SEC on August 21, 2012).
10.6
 
Contribution Agreement by and among Hi-Crush Partners LP, Hi-Crush Augusta LLC and Hi-Crush Proppants LLC, dated January 31, 2013 (incorporated by reference to Exhibit 2.1 to the Registrant’s Current Report on Form 8-K, filed with the SEC on February 5, 2013).
10.7
 
Omnibus Agreement by and among Hi-Crush Partners LP, Hi-Crush GP LLC and Hi-Crush Proppants LLC, dated August 20, 2012 (incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K, filed with the SEC on August 21, 2012).
10.8
 
First Amendment to Omnibus Agreement, among Hi-Crush Partners LP, Hi-Crush GP LLC and Hi-Crush Proppants LLC, dated January 31, 2013 (incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K, filed with the SEC on February 5, 2013).
10.9
 
Contribution Agreement by and among Hi-Crush Proppants LLC, Hi-Crush Augusta Acquisition Co. LLC and Hi-Crush Partners LP, dated April 8, 2014 (incorporated by reference to Exhibit 2.1 to the Registrant's Current Report on Form 8-K, filed with the SEC on April 29, 2014).

114


Exhibit Number        
 
Description
10.10†
 
Hi-Crush Partners LP Long-Term Incentive Plan, adopted as of August 15, 2012 (incorporated by reference to Exhibit 10.3 to the Registrant’s Current Report on Form 8-K, filed with the SEC on August 21, 2012).
10.11†
 
First Amendment to Hi-Crush Partners LP Long-Term Incentive Plan, dated effective June 2, 2014 (incorporated by reference to Exhibit 10.7 to the Registrant’s Quarterly Report on Form 10-Q, filed with the SEC on August 5, 2014).
10.12†
 
Form of Hi-Crush Partners LP Long-Term Incentive Plan Phantom Unit Award Agreement (Performance-Based Vesting) (incorporated by reference to Exhibit 10.8 to the Registrant’s Quarterly Report on Form 10-Q, filed with the SEC on August 5, 2014).
10.13†
 
Form of Hi-Crush Partners LP Long-Term Incentive Plan Phantom Unit Award Agreement (Time-Based Vesting) (incorporated by reference to Exhibit 10.9 to the Registrant’s Quarterly Report on Form 10-Q, filed with the SEC on August 5, 2014).
10.14†
 
Employment Agreement, dated May 25, 2011, between Hi-Crush Proppants LLC and Robert E. Rasmus (incorporated by reference to Exhibit 10.14 to the Registrant’s Registration Statement on Form S-1, Registration No. 333-182574, filed with the SEC on July 9, 2012).
10.15†
 
Employment Agreement, dated May 25, 2011, between Hi-Crush Proppants LLC and James M. Whipkey (incorporated by reference to Exhibit 10.15 to the Registrant’s Registration Statement on Form S-1, Registration No. 333-182574, filed with the SEC on July 9, 2012).
10.16†
 
Employment Agreement, dated May 25, 2011, between Hi-Crush Proppants LLC and Jefferies V. Alston, III (incorporated by reference to Exhibit 10.16 to the Registrant’s Registration Statement on Form S-1, Registration No. 333-182574, filed with the SEC on July 9, 2012).
10.17†
 
Letter Agreement, dated July 13, 2012, between Hi-Crush Proppants LLC and Robert E. Rasmus (incorporated by reference to Exhibit 10.19 to the Registrant’s Registration Statement on Form S-1, Registration No. 333-182574, filed with the SEC on July 25, 2012).
10.18†
 
Letter Agreement, dated July 13, 2012, between Hi-Crush Proppants LLC and James M. Whipkey (incorporated by reference to Exhibit 10.20 to the Registrant’s Registration Statement on Form S-1, Registration No. 333-182574, filed with the SEC on July 25, 2012).
10.19†
 
Letter Agreement, dated July 13, 2012, between Hi-Crush Proppants LLC and Jefferies V. Alston, III (incorporated by reference to Exhibit 10.21 to the Registrant’s Registration Statement on Form S-1, Registration No. 333-182574, filed with the SEC on July 25, 2012).
10.20†
 
Management Services Agreement, dated May 25, 2011 between Red Oak Capital Management LLC and Hi-Crush Proppants LLC (incorporated by reference to Exhibit 10.18 to the Registrant’s Registration Statement on Form S-1, Registration No. 333-182574, filed with the SEC on July 25, 2012).
10.21+
 
Supply Agreement, effective as of January 11, 2011, between Weatherford Artificial Lift Systems, Inc. and Hi-Crush Operating LLC (incorporated by reference to Exhibit 10.5 to the Registrant’s Registration Statement on Form S-1, Registration No. 333-182574, filed with the SEC on July 9, 2012).
10.22+
 
Amended and Restated First Amendment to Supply Agreement by and between Weatherford Artificial Lift Systems, L.L.C. and Hi-Crush Operating LLC, dated May 5, 2014 (incorporated by reference to Exhibit 10.2 to the Registrant’s Quarterly Report on Form 10-Q, filed with the SEC on May 5, 2014).
10.23+
 
Second Amendment to Supply Agreement, dated August 8, 2014, by and between Weatherford U.S. L.P. and Hi-Crush Operating LLC (incorporated by reference to Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q, filed with the SEC on November 4, 2014).
10.24+
 
Purchase Agreement by and between Halliburton Energy Services, Inc. and Hi-Crush Operating LLC, dated June 18, 2014 (incorporated by reference to Exhibit 10.5 to the Registrant’s Quarterly Report on Form 10-Q, filed with the SEC on August 5, 2014).
10.25*
 
First Amendment to Purchase Agreement, dated October 8, 2014, between Halliburton Energy Services, Inc. and Hi-Crush Operating LLC.
21.1
 
List of Subsidiaries of Hi-Crush Partners LP
23.1
 
Consent of PricewaterhouseCoopers LLP
23.2
 
Consent of John T. Boyd Company
23.3
 
Consent of The Freedonia Group, Inc.


115


Exhibit Number        
 
Description
31.1
 
Certification pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 signed by the Principal Executive Officer, filed herewith.
31.2
 
Certification pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 signed by the Principal Executive Officer, filed herewith.
31.3
 
Certification pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 signed by the Principal Financial Officer, filed herewith.
32.1
 
Statement Required by 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 signed by Principal Executive Officer, filed herewith. (1)
32.2
 
Statement Required by 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 signed by Principal Executive Officer, filed herewith. (1)
32.3
 
Statement Required by 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 signed by Principal Financial Officer, filed herewith. (1)
95.1
 
Mine Safety Disclosure Exhibit
101
 
Interactive Data Files- XBRL
(1)
This document is being furnished in accordance with SEC Release Nos. 33-8212 and 34-47551.
Compensatory plan or arrangement.
+    Confidential treatment has been granted with respect to portions of this exhibit.
*    Parts of the exhibit have been omitted pursuant to a request for confidential treatment.
***    Pursuant to Item 601(b)(2) of Regulation S-K, the Partnership agrees to furnish supplementally a copy of any omitted exhibit or schedule to the SEC upon request.


116


SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized, on this 27th day of February, 2015.
HI-CRUSH PARTNERS LP
 
 
By: 
Hi-Crush GP LLC, its general partner
 
 
By: 
/s/ Laura C. Fulton
 
Laura C. Fulton
Chief Financial Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of the Registrant and in the capacities indicated on February 27, 2015.
Hi-Crush Partners LP (Registrant)
By: Hi-Crush GP LLC, its general partner
Name
 
Capacity
/s/ Robert E. Rasmus
 
Co-Chief Executive Officer and Director (Principal Executive Officer)
Robert E. Rasmus
 
 
 
 
 
/s/ James M. Whipkey
 
Co-Chief Executive Officer and Director (Principal Executive Officer)
James M. Whipkey
 
 
 
 
 
/s/ Laura C. Fulton
 
Chief Financial Officer (Principal Financial and Accounting Officer)
Laura C. Fulton
 
 
 
 
 
/s/ John F. Affleck-Graves
 
Director
John F. Affleck-Graves
 
 
 
 
 
/s/ Jefferies V. Alston, III
 
Director
Jefferies V. Alston, III
 
 
 
 
 
/s/ Gregory F. Evans
 
Director
Gregory F. Evans
 
 
 
 
 
/s/ John R. Huff
 
Director
John R. Huff
 
 
 
 
 
/s/ John Kevin Poorman
 
Director
John Kevin Poorman
 
 
 
 
 
/s/ Trevor M. Turbidy
 
Director
Trevor M. Turbidy
 
 
 
 
 
/s/ R. Graham Whaling
 
Director
R. Graham Whaling
 
 
 
 
 
/s/ Joseph C. Winkler III
 
Director
Joseph C. Winkler III
 
 


117


INDEX TO FINANCIAL STATEMENTS

F-1


Report of Independent Registered Public Accounting Firm
To the Board of Directors of Hi-Crush GP LLC and Unitholders of Hi-Crush Partners LP

In our opinion, the accompanying consolidated balance sheets as of December 31, 2014 and 2013 and the related consolidated statements of operations, partners’ capital and cash flows for the years then ended and for the period from August 16, 2012 through December 31, 2012 present fairly, in all material respects, the financial position of Hi-Crush Partners LP and its subsidiaries (Successor) at December 31, 2014 and 2013, and the results of their operations and their cash flows for the years then ended and for the period from August 16, 2012 through December 31, 2012 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Partnership's management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements and on the Partnership's internal control over financial reporting based on our audits, which was an integrated audit in 2014. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

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

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


/s/ PricewaterhouseCoopers LLP
Houston, Texas
February 27, 2015


F-2


Report of Independent Registered Public Accounting Firm
To the Board of Directors of Hi-Crush GP LLC and Unitholders of Hi-Crush Partners LP

In our opinion, the consolidated statements of operations, members’ capital and cash flows for the period from January 1, 2012 through August 15, 2012 present fairly, in all material respects, the results of operations and cash flows of Hi-Crush Proppants LLC and its subsidiaries (Predecessor) for the period from January 1, 2012 to August 15, 2012, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.


/s/ PricewaterhouseCoopers LLP
Houston, Texas
March 13, 2013, except for the condensed consolidating financial information included in Note 18 to the consolidated financial statements, as to which the date is August 11, 2014


F-3


HI-CRUSH PARTNERS LP
Consolidated Balance Sheets
(In thousands, except unit amounts)
 
December 31, 2014
 
December 31, 2013(a)
Assets
 
 
 
Current assets:
 
 
 
Cash
$
4,646

 
$
20,608

Restricted cash
691

 
690

Accounts receivable, net
82,117

 
37,442

Inventories
23,684

 
22,418

Prepaid expenses and other current assets
4,081

 
1,625

Total current assets
115,219

 
82,783

Property, plant and equipment, net
241,325

 
195,834

Goodwill and intangible assets, net
66,750

 
71,936

Other assets
12,826

 
3,808

Total assets
$
436,120

 
$
354,361

Liabilities, Equity and Partners' Capital
 
 
 
Current liabilities:
 
 
 
Accounts payable
$
24,878

 
$
10,108

Accrued and other current liabilities
12,248

 
7,669

Due to sponsor
13,459

 
10,352

Current portion of long-term debt
2,000

 

Total current liabilities
52,585

 
28,129

Long-term debt
198,364

 
138,250

Asset retirement obligation
6,730

 
4,628

Total liabilities
257,679

 
171,007

Commitments and contingencies

 

Equity and Partners' capital:
 
 
 
General partner interest

 

Limited partner interest, 36,952,426 and 28,865,171 units outstanding, respectively
175,962

 
138,580

Class B units, zero and 3,750,000 units outstanding, respectively

 
9,543

Total partners' capital
175,962

 
148,123

Non-controlling interest
2,479

 
35,231

Total equity and partners' capital
178,441

 
183,354

Total liabilities, equity and partners' capital
$
436,120

 
$
354,361

(a) Financial information has been recast to include the financial position and results attributable to Hi-Crush Augusta LLC. See Note 9.
See Notes to Consolidated Financial Statements.

F-4


HI-CRUSH PARTNERS LP
Consolidated Statements of Operations
(In thousands, except unit and per unit amounts)
 
For the Year Ended December 31, 2014
 
For the Year Ended December 31, 2013(a)
 
Period From August 16 Through December 31, 2012(a)
 
Period From January 1 Through August 15, 2012    
 
Successor
 
Successor
 
Successor
 
Predecessor
Revenues
$
386,547

 
$
178,970

 
$
31,770

 
$
46,776

Cost of goods sold (including depreciation, depletion and amortization)
225,984

 
95,884

 
10,053

 
13,336

Gross profit
160,563

 
83,086

 
21,717

 
33,440

Operating costs and expenses:
 
 
 
 
 
 
 
General and administrative expenses
26,346

 
19,096

 
3,757

 
4,631

Exploration expense

 
47

 
121

 
539

Accretion of asset retirement obligation
246

 
228

 
102

 
16

Income from operations
133,971

 
63,715

 
17,737

 
28,254

Other income (expense):
 
 
 
 
 
 
 
Other income

 

 

 
6

Interest expense
(9,946
)
 
(3,671
)
 
(320
)
 
(3,240
)
Net income
124,025

 
60,044

 
17,417

 
25,020

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

 

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

 
$
59,770

 
$
17,440

 
$
25,020

Earnings per unit:
 
 
 
 
 
 
 
Common units - basic
$
3.09

 
$
2.08

 
$
0.68

 
 
Subordinated units - basic
$
3.09

 
$
2.08

 
$
0.68

 
 
Common units - diluted
$
3.00

 
$
2.08

 
$
0.68

 
 
Subordinated units - diluted
$
3.00

 
$
2.08

 
$
0.68

 
 
(a) Financial information has been recast to include the financial position and results attributable to Hi-Crush Augusta LLC. See Note 9.
See Notes to Consolidated Financial Statements.

F-5


HI-CRUSH PARTNERS LP
Consolidated Statements of Cash Flows
(In thousands)
 
 
Year Ended December 31, 2014
 
Year Ended December 31, 2013(a)
 
Period From August 16 Through December 31, 2012(a)
 
Period From January 1 Through August 15, 2012
 
 
Successor
 
Successor
 
Successor
 
Predecessor
Operating activities:
 
 
 
 
 
 
 
 
Net income
 
$
124,025

 
$
60,044

 
$
17,417

 
$
25,020

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
 
 
 
 
 
Depreciation and depletion
 
8,858

 
6,132

 
1,109

 
1,089

Amortization of intangible assets
 
5,186

 
3,687

 

 

Amortization of deferred charges into interest expense
 
1,264

 
463

 
105

 
364

Management fees paid by Member on behalf of Hi-Crush Augusta LLC
 
492

 
1,424

 
674

 

Accretion of asset retirement obligation
 
246

 
228

 
102

 
16

Loss on replacement of equipment
 

 
191

 

 

Unit-based compensation to independent directors and employees
 
1,470

 
100

 

 

Income from restricted cash
 

 
(2
)
 

 

Interest expense converted into principal
 

 

 

 
3,083

Changes in operating assets and liabilities:
 
 
 
 
 
 
 
 
Accounts receivable
 
(44,675
)
 
(10,201
)
 
3,391

 
(8,698
)
Prepaid expenses and other current assets
 
(2,360
)
 
(250
)
 
(486
)
 
(4,549
)
Inventories
 
(1,738
)
 
(4,034
)
 
(2,747
)
 
(2,052
)
Other assets
 
(2,974
)
 
(2,234
)
 

 

Accounts payable
 
6,890

 
(4,201
)
 
(775
)
 
2,814

Accrued liabilities and other current liabilities
 
4,579

 
4,339

 
584

 
2,161

Due to sponsor
 
3,107

 
10,352

 

 

Deferred revenue
 

 
(1,715
)
 
(4,876
)
 
(2,588
)
Net cash provided by operating activities
 
104,370

 
64,323

 
14,498

 
16,660

Investing activities:
 
 
 
 
 
 
 
 
Acquisition of Hi-Crush Augusta LLC
 
(224,250
)
 

 

 

Cash paid for acquisition of D&I Silica LLC, net of cash acquired
 

 
(94,955
)
 

 

Capital expenditures for property, plant and equipment
 
(40,465
)
 
(10,630
)
 
(8,218
)
 
(80,075
)
Decrease in restricted cash
 

 

 

 
30

Net cash used in investing activities
 
(264,715
)
 
(105,585
)
 
(8,218
)
 
(80,045
)
Financing activities:
 
 
 
 
 
 
 
 
Proceeds from equity issuance, net
 
170,693

 

 

 

Proceeds from issuance of long-term debt
 
198,000

 
138,250

 

 
63,985

Repayment of long-term debt
 
(139,750
)
 
(33,250
)
 

 
(1,250
)
Affiliate financing, net
 

 
5,615

 
4,250

 

Loan origination costs
 
(7,120
)
 
(829
)
 
(143
)
 
(1,462
)
Redemption of common units
 
(19
)
 

 

 

Distributions paid
 
(77,421
)
 
(58,414
)
 
(6,479
)
 
(225
)
Contributions received
 

 

 
4,606

 

Net cash provided by financing activities
 
144,383

 
51,372

 
2,234

 
61,048

Net (decrease) increase in cash
 
(15,962
)
 
10,110

 
8,514

 
(2,337
)
Cash:
 
 
 
 
 
 
 
 
Beginning of period
 
20,608

 
10,498

 
1,984

 
11,054

End of period
 
$
4,646

 
$
20,608

 
$
10,498

 
$
8,717

Non-cash investing and financing activities:
 
 
 
 
 
 
 
 
Increase (decrease) in accounts payable and accrued liabilities for additions to property, plant and equipment
 
$
7,880

 
$
(1,994
)
 
$
4,093

 
$
9,345

Affiliate debts converted into non-controlling interest
 

 
38,172

 

 

Issuance of common units for acquisition of D&I Silica, LLC
 

 
37,538

 

 

Increase (decrease) in accounts payable for loan origination costs
 

 

 
(56
)
 
1,238

Non-cash component of capital contribution by sponsor to the Partnership
 

 

 
81,170

 

Debt financed capital expenditures
 
3,676

 

 

 

Increase in property, plant and equipment for asset retirement obligation
 
1,857

 

 

 

Cash paid for interest, net of amount capitalized
 
$
8,682

 
$
3,123

 
$
120

 
$
90

(a) Financial information has been recast to include the financial position and results attributable to Hi-Crush Augusta LLC. See Note 9.
See Notes to Consolidated Financial Statements

F-6


HI-CRUSH PARTNERS LP
Successor Consolidated Statements of Partners’ Capital
(In thousands)
 
General Partner Capital
 
Sponsor Class B Units
 
Limited Partners
 
 
 
 
 
 
 
Public Common Unit Capital    
 
Sponsor Common Unit Capital    
 
Sponsor Subordinated Unit Capital    
 
Total Limited Partner Capital    
 
Total Partner Capital
 
Non-Controlling Interest
 
Total Equity and Partners Capital
Balance at May 8, 2012 (Inception)
$

 
$

 
$

 
$

 
$

 
$

 
$

 
$

 
$

Contribution of net assets on August 16, 2012

 

 
39,435

 
2,142

 
41,577

 
83,154

 
83,154

 

 
83,154

Capital contributions associated with recast of Hi-Crush Augusta LLC(a)

 

 
480

 
27

 
507

 
1,014

 
1,014

 
21

 
1,035

Net income from August 16, 2012 to December 31, 2012(a)

 

 
8,272

 
449

 
8,719

 
17,440

 
17,440

 
(23
)
 
17,417

Cash distributions

 

 
(3,073
)
 
(166
)
 
(3,240
)
 
(6,479
)
 
(6,479
)
 

 
(6,479
)
Balance at December 31, 2012

 

 
45,114

 
2,452

 
47,563

 
95,129

 
95,129

 
(2
)
 
95,127

Issuance of 5,522 common units to independent directors

 

 
100

 

 

 
100

 
100

 

 
100

Issuance of 1,578,947 common units in acquisition of D&I Silica, LLC

 

 
37,358

 

 

 
37,358

 
37,358

 

 
37,358

Conversion of advances to Hi-Crush Proppants LLC(a)

 
9,543

 

 

 

 

 
9,543

 
38,172

 
47,715

Management fees paid by sponsor on behalf of the Partnership(a)

 

 

 

 

 

 

 
1,424

 
1,424

Cash distributions (a)

 

 
(26,310
)
 
(1,346
)
 
(26,121
)
 
(53,777
)
 
(53,777
)
 
(4,637
)
 
(58,414
)
Net income(a)

 

 
29,586

 
1,367

 
28,817

 
59,770

 
59,770

 
274

 
60,044

Secondary offering of units by sponsor

 

 
2,473

 
(2,473
)
 

 

 

 

 

Balance at December 31, 2013

 
9,543

 
88,321

 

 
50,259

 
138,580

 
148,123

 
35,231

 
183,354

Issuance of 12,554 common units to independent directors and employees

 

 
458

 

 

 
458

 
458

 

 
458

Unit based compensation

 

 
1,109

 

 

 
1,109

 
1,109

 

 
1,109

Management fees paid by sponsor on behalf of the Partnership(a)

 

 

 

 

 

 

 
492

 
492

Issuance of 4,325,000 common units

 

 
170,693

 

 

 
170,693

 
170,693

 

 
170,693

Acquisition of 390,000 common units of Hi-Crush Augusta LLC

 

 
(111,794
)
 

 
(78,257
)
 
(190,051
)
 
(190,051
)
 
(34,199
)
 
(224,250
)
Redemption of 299 common units

 

 
(19
)
 

 

 
(19
)
 
(19
)
 

 
(19
)
Conversion of Class B units into 3,750,000 common units

 
(9,543
)
 

 
9,543

 

 
9,543

 

 

 

Cash distributions (a)
(863
)
 

 
(43,917
)
 
(2,156
)
 
(30,485
)
 
(76,558
)
 
(77,421
)
 

 
(77,421
)
Net income(a)
863

 

 
72,404

 

 
49,803

 
122,207

 
123,070

 
955

 
124,025

Secondary offering of 3,750,000 common units by sponsor

 

 
7,387

 
(7,387
)
 

 

 

 

 

Balance at December 31, 2014
$

 
$

 
$
184,642

 
$

 
$
(8,680
)
 
$
175,962

 
$
175,962

 
$
2,479

 
$
178,441

(a) Financial information has been recast to include the financial position and results attributable to Hi-Crush Augusta LLC. See Note 9.
See Notes to Consolidated Financial Statements

F-7


HI-CRUSH PARTNERS LP
Predecessor Consolidated Statements of Members’ Capital
(In thousands)
 
Members’ Equity
 
Accumulated  Earnings
 
Total Members’ Capital
Balance at January 1, 2011
336

 
(26
)
 
310

Distributions
(400
)
 

 
(400
)
Contributions
1,097

 

 
1,097

Net income

 
9,280

 
9,280

Balance at December 31, 2011
1,033

 
9,254

 
10,287

Net income

 
25,020

 
25,020

Cash distributions
(225
)
 

 
(225
)
Balance at August 15, 2012
$
808

 
$
34,274

 
$
35,082

See Notes to Consolidated Financial Statements

F-8


HI-CRUSH PARTNERS LP
Notes to Consolidated Financial Statements
(Dollars in thousands, except per ton and per unit amounts, or where otherwise noted)

F-9


1. Business and Organization
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. The Partnership is engaged in the excavation and processing of raw frac sand for use in hydraulic fracturing operations for oil and natural gas wells. In connection with its formation, the Partnership issued (a) a non-economic general partner interest to Hi-Crush GP LLC (the “General Partner”), and (b) a 100.0% limited partner interest to Hi-Crush Proppants LLC (the “sponsor”), its organizational limited partner.
Through August 15, 2012, Hi-Crush Proppants LLC owned 100% of the sand reserves and related excavation and processing facilities located in Wyeville, Wisconsin (“Wyeville Plant”). On August 16, 2012, the sponsor contributed its ownership of Hi-Crush Chambers LLC, Hi-Crush Railroad LLC, Hi-Crush Wyeville LLC, Hi-Crush Operating LLC and $4,606 of cash to the Partnership (the “Contribution”). In addition, the sponsor agreed to (1) convert all $23,916 of consolidated net intercompany receivables due from the Partnership into capital and (2) assume via capital contribution $10,028 of outstanding accounts payable maintained by Hi-Crush Operating LLC as of the transaction date. In return, the Partnership issued 13,640,351 common units and 13,640,351 subordinated units to the sponsor. In connection with this transaction, the Partnership also completed an initial public offering through the sale of 12,937,500 of the common units by the sponsor.
The Partnership considers all contributed assets to be under common control with Hi-Crush Proppants LLC. As such, we are presenting the consolidated historical financial statements of Hi-Crush Proppants LLC as our historical financial statements as we believe they provide a representation of our management’s ability to execute and manage our business plan. The financial statement data and operations of Hi-Crush Proppants LLC are referred to herein as “Predecessor,” whereas operations following the initial public offering ("IPO") on August 16, 2012 are referred to herein as “Successor”.
On January 31, 2013, the Partnership entered into an agreement with the sponsor to acquire a preferred interest in Hi-Crush Augusta LLC, the entity that owned the sponsor’s Augusta raw frac sand processing facility, for $37,500 in cash and 3,750,000 of newly issued convertible Class B units in the Partnership (See Augusta Contribution below). The 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, upon such payment, the 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 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. The 3,750,000 converted common units were sold to the public on August 15, 2014.
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 $95,159 in cash and 1,578,947 common units (See Note 5 – Business Combination – Acquisition Accounting). 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.
On April 8, 2014, the Partnership entered into a contribution agreement with the sponsor to acquire substantially all of the remaining equity interests in the 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 owned 98% 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 (See Note 10 - Long-Term Debt).

F-10


2. Basis of Presentation
The consolidated financial statements through August 15, 2012 include the consolidated results of operations and cash flows, as well as the financial position of the sponsor (the "Predecessor").
The consolidated financial statements from August 16, 2012 through December 31, 2014 include the consolidated results of operations and cash flows of the Partnership (the "Successor"). The consolidated financial statements include results of operations and cash flows for D&I prospectively from June 11, 2013.
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. Refer to Note 9 for additional disclosure regarding the Augusta Contribution.


F-11


3. Significant Accounting Policies
Use of Estimates
The preparation of the financial statements in conformity with accounting principles generally accepted in the United States of America (“GAAP”) requires management to make estimates and assumptions that affect the reported amount of assets and liabilities and disclosure of contingent liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. The more significant estimates relate to purchase accounting allocations and valuations, estimates and assumptions for our mineral reserves and its impact on calculating our depreciation and depletion expense under the units-of-production depreciation method, assessing potential impairment of long-lived assets, estimating potential loss contingencies, inventory valuation, valuation of unit based compensation and estimated cost of future asset retirement obligations. Actual results could differ from those estimates.
Cash and Cash Equivalents
Cash and cash equivalents consist of all cash balances and highly liquid investments with an original maturity of three months or less.
Restricted Cash
The Partnership must pledge cash escrow accounts for the benefit of the Pennsylvania Department of Transportation, Bureau of Rail Freight, Ports and Waterways (the “Bureau”) to guarantee performance on rail improvement projects partially funded by the Bureau. The funds are released when the project is completed.
Accounts Receivable
Trade receivables relate to sales of raw frac sand and related services for which credit is extended based on the customer’s credit history and are recorded at the invoiced amount and do not bear interest. The Partnership regularly reviews the collectability of accounts receivable. When it is probable that all or part of an outstanding balance will not be collected, the Partnership establishes or adjusts an allowance as necessary using the specific identification method. Account balances are charged against the allowance after all means of collection have been exhausted and potential recovery is considered remote. As of December 31, 2014 and 2013, the Partnership maintained an allowance for doubtful accounts of $984 and $300, respectively.
Deferred Charges
Certain direct costs incurred in connection with debt financing have been capitalized and are being amortized using the straight-line method, which approximates the effective interest method, over the life of the debt. Amortization expense is included in interest expense and was $1,264 for the year ended December 31, 2014, $463 for the year ended December 31, 2013, $105 for the period from August 16, 2012 to December 31, 2012 and $364 for the period from January 1, 2012 to August 15, 2012.
The following is a summary of future amortization expense associated with deferred charges:
For the years ending December 31,
 
2015
$
1,363

2016
1,363

2017
1,363

2018
1,363

2019
984

Thereafter
1,075

Total
$
7,511

Inventories
Sand inventory is stated at the lower of cost or market using the average cost method.
Inventory manufactured at our plant facilities includes direct excavation costs, processing costs, overhead allocation, depreciation and depletion. Stockpile tonnages are calculated by measuring the number of tons added and removed from the stockpile. Tonnages are verified periodically by an independent surveyor. Costs are calculated on a per ton basis and are applied to the stockpile based on the number of tons in the stockpile.
Inventory transported for sale at our terminal facilities includes the cost of purchased or manufactured sand, plus transportation related charges.
Spare parts inventory includes critical spares, materials and supplies. We account for spare parts on a first-in, first-out basis, and value the inventory at the lower of cost or market. Detail reviews are performed related to the net realizable value of the spare parts inventory, giving consideration to quality, excessive levels, obsolescence and other factors.



F-12


Property, Plant and Equipment
Additions and improvements occurring through the normal course of business are capitalized at cost. When assets are retired or disposed of, the cost and the accumulated depreciation and depletion are eliminated from the accounts and any gain or loss is reflected in the income statement. Expenditures for normal repairs and maintenance are expensed as incurred. Construction-in-progress is primarily comprised of machinery and equipment which has not been placed in service.
Mine development costs include engineering, mineralogical studies, drilling and other related costs to develop the mine, the removal of overburden to initially expose the mineral and building access ways. Exploration costs are expensed as incurred and classified as exploration expense. Capitalization of mine development project costs begins once the deposit is classified as proven and probable reserves.
Drilling and related costs are capitalized for deposits where proven and probable reserves exist and the activities are directed at obtaining additional information on the deposit or converting non-reserve minerals to proven and probable reserves and the benefit is to be realized over a period greater than one year.
Mining property and development costs are amortized using the units-of-production (“UOP”) method on estimated measured tons in in-place reserves. The impact of revisions to reserve estimates is recognized on a prospective basis.
Capitalized costs incurred during the year for major improvement and capital projects that are not placed in service are recorded as construction-in-progress. Construction-in-progress is not depreciated until the related assets or improvements are ready to be placed in service. We capitalize interest cost as part of the historical cost of constructing an asset and preparing it for its intended use. These interest costs are included in the property, plant and equipment line in the balance sheet. The Partnership did not capitalize any interest for the period from August 16, 2012 to December 31, 2014. Capitalized interest was $1,739 for the period from January 1, 2012 to August 15, 2012.
Fixed assets other than plant facilities and buildings associated with productive, depletable properties are carried at historical cost and are depreciated using the straight-line method over the estimated useful lives of the assets, as follows:
Computer equipment
3 years
Furniture and fixtures
7 years
Vehicles
5 years
Equipment
5-15 years
Rail spur and asset retirement obligation
33 years
Rail and rail equipment
15-20 years
Transload facilities and equipment
15-20 years
Plant facilities and buildings associated with productive, depletable properties that contain frac sand reserves are carried at historical cost and are depreciated using the units-of-production method. Units-of-production rates are based on the amount of proved developed frac sand reserves that are estimated to be recoverable from existing facilities using current operating methods.
Impairment of Long-lived Assets
Recoverability of investments in property, plant and equipment, and mineral rights is evaluated annually. Estimated future undiscounted net cash flows are calculated using estimates of proven and probable sand reserves, estimated future sales prices (considering historical and current prices, price trends and related factors) and operating costs and anticipated capital expenditures. Reductions in the carrying value of our investment are only recorded if the undiscounted cash flows are less than our book basis in the applicable assets.
Impairment losses are recognized based on the extent that the remaining investment exceeds the fair value, which is determined based upon the estimated future discounted net cash flows to be generated by the property, plant and equipment and mineral rights.
Management’s estimates of prices, recoverable proven and probable reserves and operating and capital costs are subject to certain risks and uncertainties which may affect the recoverability of our investments in property, plant and equipment. Although management has made its best estimate of these factors based on current conditions, it is reasonably possible that changes could occur in the near term, which could adversely affect management’s estimate of the net cash flows expected to be generated from its operating property. No impairment charges were recorded during 2014, 2013 or 2012.
Goodwill and Intangible Assets
Goodwill represents the excess of purchase price over the fair value of net assets acquired. The Partnership performs an assessment of the recoverability of goodwill during the third quarter of each fiscal year, or more often if events or circumstances indicate the impairment of an asset may exist. Our assessment of goodwill is based on qualitative factors to determine whether the fair value of the reporting unit is more likely than not less than the carrying value. An additional quantitative impairment analysis is completed if the qualitative analysis indicates that the fair value is not substantially in excess of the carrying value. The quantitative analysis determines the fair value of the reporting unit based on the discounted cash flow method and relative market-based approaches. No impairment charges related to goodwill were recorded during the years ended December 31, 2014 and 2013, respectively.

F-13


The Partnership amortizes the cost of other intangible assets on a straight line basis over their estimated useful lives, ranging from 1 to 20 years. An impairment assessment is performed if events or circumstances occur and may result in the change of the useful lives of the intangible assets. No impairment charges related to intangible assets were recorded during the years ended December 31, 2014 and 2013.
Revenue Recognition
Frac sand sales revenues are recognized when legal title passes to the customer, which may occur at the production facility, rail origin or at the destination terminal. At that point, delivery has occurred, evidence of a contractual arrangement exists and collectability is reasonably assured. Amounts received from customers in advance of sand deliveries are recorded as deferred revenue. Revenue from make-whole provisions in our customer contracts is recognized at the end of the defined cure period.
The majority of our frac sand is sold under long-term supply agreements, the current terms of which expire between 2016 and 2019. The agreements define, among other commitments, the volume of product that the Partnership must provide, the price that will be charged to the customer, and the volume that the customer must purchase at the end of the defined cure period, which can range from three months to the end of a contract year.
Transportation services revenues are recognized as the services have been completed, meaning the related services have been rendered. At that point, delivery of service has occurred, evidence of a contractual arrangement exists and collectability is reasonably assured. Amounts received from customers in advance of transportation services being rendered are recorded as deferred revenue.
Revenue attributable to silo storage leases is recorded on a straight-line basis over the term of the lease.
Deferred Revenue
In January 2011, the sponsor received $16,500 in an advance payment from a customer for a certain volume of product to be delivered over a one-year period starting in July 2011. Revenue was recognized as product was delivered and the deferred revenue obligation was recognized over the one-year period ended June 30, 2012. In July 2012, the sponsor received an $8,250 advance payment from a customer for a certain volume of frac sand to be delivered over the six-month period beginning in July 2012. As of August 15, 2012, the outstanding balance under this obligation was $6,590 while the cash held by the Partnership was $1,984. As a result, the sponsor made a cash contribution of $4,606 to align the cash balance with the outstanding balance under this advance. As of December 31, 2014 and 2013, no deferred revenue balance was outstanding under this advance payment.
Asset Retirement Obligation
In accordance with Accounting Standards Codification (“ASC”) 410-20, Asset Retirement Obligations, we recognize reclamation obligations when incurred and record them as liabilities at fair value. In addition, a corresponding increase in the carrying amount of the related asset is recorded and depreciated over such asset’s useful life. The reclamation liability is accreted to expense over the estimated productive life of the related asset and is subject to adjustments to reflect changes in value resulting from the passage of time and revisions to the estimates of either the timing or amount of the reclamation costs.
Fair Value of Financial Instruments
The amounts reported in the balance sheet as current assets or liabilities, including cash, accounts receivable, accounts payable, accrued liabilities and deferred revenue approximate fair value due to the short-term maturities of these instruments.
The amounts reported in the balance sheet as current assets or liabilities, including cash, accounts receivable, accounts payable, accrued and other current liabilities approximate fair value due to the short-term maturities of these instruments. The fair value of the senior secured term loan approximated $189,071 as of December 31, 2014, based on the market price quoted from external sources, compared with a carrying value of $198,500. If the senior secured term loan was measured at fair value in the financial statements, it would be classified as Level 2 in the fair value hierarchy.
Net Income per Limited Partner Unit
We have identified the sponsor’s incentive distribution rights as participating securities and compute income per unit using the two-class method under which any excess of distributions declared over net income shall be allocated to the partners based on their respective sharing of income specified in the partnership agreement. Net income per unit applicable to limited partners (including subordinated unitholders) is computed by dividing limited partners’ interest in net income, after deducting any sponsor incentive distributions, by the weighted-average number of outstanding common and subordinated units. Through March 31, 2014, basic and diluted net income per unit are the same as there were no potentially dilutive common or subordinated units outstanding.
Through August 15, 2014, the 3.75 million Class B units outstanding did not have voting rights or rights to share in the Partnership’s periodic earnings, either through participation in its distributions or through an allocation of its undistributed earnings or losses, and so were not deemed to be participating securities in their form as Class B units. In addition, the conversion of the Class B units into common units was fully contingent upon the satisfaction of defined criteria pertaining to the cumulative payment of distributions and earnings per unit of the Partnership as described in Note 11. Until all of the defined payment and earnings criteria were satisfied, the Class B units were not included in our calculation of either basic or diluted earnings per unit. As such, for the quarter ended June 30, 2014, the Class B units were included in our calculation of diluted earnings per unit. On August 15, 2014, the Class B units converted into common units, at which time income allocations commenced on such units and the common units were included in our calculation of basic and diluted earnings per unit.

F-14


As described in Note 2, the Partnership's historical financial information has been recast to consolidate Augusta for all periods presented. The amounts of incremental income or losses recasted to periods prior to the Augusta Contribution are excluded from the calculation of net income per limited partner unit.
Income Taxes
The Partnership and sponsor are pass-through entities and are not considered taxable entities for federal tax purposes. Therefore, there is not a provision for income taxes in the accompanying condensed consolidated financial statements. The Partnership’s net income or loss is allocated to its partners in accordance with the partnership agreement. The partners are taxed individually on their share of the Partnership’s earnings. At December 31, 2014 and 2013, the Partnership did not have any liabilities for uncertain tax positions or gross unrecognized tax benefit.
Recent Accounting Pronouncements
In August 2014, the Financial Accounting Standards Board ("FASB") issued ASU 2014-15, which provides guidance on determining when and how to disclose going-concern uncertainties in the financial statements. The new standard requires management to perform interim and annual assessments of an entity’s ability to continue as a going concern within one year of the date the financial statements are issued. An entity must provide certain disclosures if "conditions or events raise substantial doubt about the entity’s ability to continue as a going concern." The ASU applies to all entities and is effective for annual periods ending after December 15, 2016, and interim periods thereafter, with early adoption permitted. The Partnership is currently evaluating the future disclosure requirements under this guidance.
In June 2014, the FASB issued amended guidance on accounting for share-based payments when the terms of an award provide that a performance target could be achieved after the requisite service period. The amended guidance, which may be applied on a prospective or retrospective basis, will be effective for the Partnership beginning January 1, 2016. The Partnership anticipates that the adoption of this amended guidance will not materially affect its financial position, results of operations or cash flows.
In May 2014, the FASB issued an update that supersedes most current revenue recognition guidance, as well as some cost recognition guidance. The update requires that an entity recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This update also requires new qualitative and quantitative disclosures about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts, including significant judgments and changes in judgments, information about contract balances and performance obligations, and assets recognized from costs incurred to obtain or fulfill a contract. The authoritative guidance, which may be applied on a full retrospective or modified retrospective basis whereby the entity records a cumulative effect of initially applying this update at the date of initial application, will be effective for the Partnership beginning January 1, 2017. Early adoption is not permitted. The Partnership is currently evaluating the potential method and impact of this authoritative guidance on its consolidated financial statements.


F-15


4. Initial Public Offering
On August 16, 2012, we completed our IPO of 11,250,000 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 $179,536 after taking into account our underwriting discount of $11,714. Our sponsor received all proceeds from the IPO and incurred capitalized transaction costs of $3,383 through September 30, 2012. These capitalized transaction costs were retained by the sponsor. On August 16, 2012, our underwriters exercised their option to purchase an additional 1,687,500 common units for $26,930. As a result, total net proceeds were $206,466 from the sale of 12,937,500 total common units to the public.
The following table outlines the consolidated net assets contributed to the Partnership on August 16, 2012:
Assets:
 
Cash
$
1,984

Accounts receivable
12,453

Inventories
4,085

Due from sponsor
4,606

Prepaid expenses and other current assets
26

Property, plant and equipment, net
69,623

Deferred charges, net
1,113

Total Assets
$
93,890

Liabilities:
 
Accounts payable
$
1,397

Accrued liabilities
1,901

Deferred revenue
6,590

Asset retirement obligation
848

Total liabilities
10,736

Net assets contributed to the Partnership
$
83,154

The following is a reconciliation of the Predecessor’s equity as of August 15, 2012 and total net assets contributed to the Partnership on August 16, 2012:
Predecessor Members’ Capital – August 15, 2012
$
35,082

Net liabilities of non-contributed sponsor entities
9,522

Members’ capital attributable to entities contributed to the Partnership
44,604

Conversion of debts payable by Partnership entities to sponsor
23,916

Assumption of payables held by Partnership entities by sponsor
10,028

Cash contribution commitment from sponsor
4,606

Net assets contributed to Partnership – August 16, 2012
$
83,154

As a result of our IPO, our sponsor entered into or amended the following agreements:
Amended and Restated Agreement of Limited Partnership of Hi-Crush Partners LP
On August 20, 2012, the Partnership amended and restated its Limited Partnership Agreement to establish the organizational framework for a public master limited partnership. On January 31, 2013, the Partnership amended and restated its amended and restated Limited Partnership Agreement to, among other things, provide for the creation of the Class B units. See Note 11 – Equity.
Omnibus Agreement
On August 20, 2012, we entered into an omnibus agreement with both 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 IPO 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 the Wyeville 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.




F-16


Services Agreement
Effective August 16, 2012, we entered into a services agreement (the “Services Agreement”) by and among our General Partner, Hi-Crush Services LLC (“Hi-Crush Services”), a wholly-owned subsidiary of the sponsor, and the Partnership, pursuant to which Hi-Crush Services provides certain management and administrative services to our General Partner to assist in operating our business. Under the Services Agreement, the Partnership reimburses Hi-Crush Services and its affiliates, on a monthly basis, for the allocable expenses it incurs in its performance under the Services Agreement. These expenses include, among other things, salary, bonus, incentive compensation, rent and other administrative expense for individuals and entities that perform services for us or on our behalf. Hi-Crush Services and its affiliates are not liable to us for its performance of services under the Services Agreement except a liability resulting from gross negligence.
Long-Term Incentive Plan
On August 21, 2012, the General Partner adopted the Hi-Crush Partners LP Long Term Incentive Plan (the “Plan”) for employees, consultants and directors of the General Partner and those of its affiliates, including the sponsor, who perform services for the Partnership. The Plan consists of restricted units, unit options, phantom units, unit payments, unit appreciation rights, other equity-based awards, distribution equivalent rights, and performance awards. The Plan limits the number of common units that may be delivered pursuant to awards under the plan to 1,364,035 units. Common units withheld to satisfy exercise prices or tax withholding obligations are available for delivery pursuant to other awards. The Plan is administered by the General Partner’s Board of Directors or a committee thereof. See Note 12 – Unit Based Compensation.

F-17


5. Business Combination – Acquisition Accounting
On June 10, 2013, the Partnership acquired D&I, an independent frac sand supplier, transforming the Partnership into an integrated Northern White frac sand producer, transporter, marketer and supplier. The Partnership acquired D&I for $95,159 in cash and 1,578,947 common units, valued at $37,358 as of June 10, 2013.
The acquisition was accounted for under the acquisition method of accounting whereby management assessed the net assets acquired and recognized amounts for the identified assets acquired and liabilities assumed.
The total purchase price of $132,517 was allocated to the net assets acquired as follows:
Assets acquired:
 
Cash
$
204

Restricted cash
688

Accounts receivable
17,908

Inventories
10,372

Prepaid expenses and other current assets
809

Property, plant and equipment
39,242

Intangible assets
41,878

Goodwill
33,745

Other assets
113

Total assets acquired
$
144,959

Liabilities assumed:
 
Accounts payable
$
11,646

Accrued liabilities and other current liabilities
796

Total liabilities assumed
12,442

Fair value of net assets acquired
$
132,517

The operations of D&I have been included in the financial statements prospectively from June 11, 2013. In connection with this acquisition, the Partnership incurred $1,728 of acquisition-related costs, as included in general and administrative expenses during the year ended December 31, 2013.
The following tables summarize the supplemental condensed consolidated statements of operations information on an unaudited pro forma basis as if the acquisition had occurred at January 1, 2012. The tables include adjustments that were directly attributable to the acquisition or are not expected to have a future impact on the Partnership. The pro forma results are for illustrative purposes only and are not intended to be indicative of the actual results that would have occurred should the transaction have been consummated at the beginning of the period, nor are they indicative of future results of operations.
Pro Forma Financial Information for the:
 
Year Ended December 31, 2013
 
Year Ended December 31, 2012
 
Successor
 
Pro Forma (1)
Revenues
$
234,022

 
$
182,398

Net income
$
69,895

 
$
61,365

Net income per limited partner unit:
 
 
 
Common units – basic and diluted
2.37

 
2.16

Subordinated units – basic and diluted
2.37

 
2.16

(1) The comparative period includes the combination of the Predecessor and Successor results before and after our IPO on August 16, 2012. These pro-forma results are for illustrative purposes only and are not intended to be indicative of the actual results that would have occurred if the acquisition and IPO would have taken place on January 1, 2012.









F-18


The pro forma financial information includes the impact of the following pro forma adjustments:
Adjustments Utilized to Prepare the Pro Forma Financial Information for the:
 
Year Ended December 31, 2013
 
Year Ended December 31, 2012
Debit / (Credit)
Successor
 
Pro Forma (1)
Acquisition related expenses
$
(4,775
)
 
$

Other general and administrative expenses
(117
)
 
(239
)
Interest expense on debt issued to fund acquisition
1,226

 
2,561

Depreciation and amortization expense
(8
)
 
3,947

Increase in weighted average common units outstanding
696,467

 
1,578,947

(1) The comparative period includes the combination of the Predecessor and Successor results before and after our IPO on August 16, 2012. These pro-forma results are for illustrative purposes only and are not intended to be indicative of the actual results that would have occurred if the acquisition and IPO would have taken place on January 1, 2012.

F-19


6. Goodwill and Intangible Assets
Changes in goodwill and intangible assets consisted of the following:
 
Goodwill
 
Intangible Assets
Additions from D&I acquisition
$
33,745

 
$
41,878

Amortization expense

 
(3,687
)
Balance at December 31, 2013
33,745

 
38,191

Amortization expense

 
(5,186
)
Balance at December 31, 2014
$
33,745

 
$
33,005

Goodwill
As of December 31, 2014, the Partnership had goodwill of $33,745 based on the allocation of the purchase price of its acquisition of D&I.
Intangible Assets
Intangible assets arising from the acquisition of D&I consisted of the following:
 
Useful life
 
December 31,
2014
 
December 31,
2013
Supplier agreements
1-20 Years
 
$
21,997

 
$
21,997

Customer contracts and relationships
1-10 Years
 
18,132

 
18,132

Other intangible assets
1-3 Years
 
1,749

 
1,749

Intangible assets
 
 
41,878

 
41,878

Less: Accumulated amortization
 
 
(8,873
)
 
(3,687
)
Intangible assets, net
 
 
$
33,005

 
$
38,191

Amortization expense was $5,186 and $3,687 for the years ended December 31, 2014 and 2013, respectively. The weighted average remaining life of intangible assets was 12 years as of December 31, 2014. As of December 31, 2014, future amortization is as follows:
Fiscal Year
 
Amortization
2015
 
$
2,932

2016
 
2,913

2017
 
2,850

2018
 
2,850

2019
 
2,850

Thereafter
 
18,610

 
 
$
33,005



F-20


7. Inventories
Inventories consisted of the following:
 
December 31,
2014
 
December 31,
2013
Raw material
$
63

 
$
706

Work-in-progress
8,892

 
9,075

Finished goods
13,441

 
11,585

Spare parts
1,288

 
1,052

 
$
23,684

 
$
22,418


F-21


8. Property, Plant and Equipment
Property, plant and equipment consisted of the following:
 
December 31,
2014
 
December 31,
2013
Buildings
$
3,930

 
$
3,815

Mining property and mine development
46,967

 
39,690

Plant and equipment
134,870

 
108,627

Rail and rail equipment
23,161

 
20,421

Transload facilities and equipment
31,742

 
30,265

Construction-in-progress
18,519

 
2,683

 
259,189

 
205,501

Less: Accumulated depreciation and depletion
(17,864
)
 
(9,667
)
 
$
241,325

 
$
195,834

Depreciation and depletion expense, net of amounts capitalized as a component of inventory, was as follows during the periods presented:
Predecessor Period
 
Period from January 1 through August 15, 2012
$
1,089

Successor Periods
 
Period from August 16 through December 31, 2012
$
1,109

Year ended December 31, 2013
6,132

Year ended December 31, 2014
8,858


F-22


9. Acquisition of Hi-Crush Augusta LLC
On January 31, 2013, the Partnership entered into an agreement with our sponsor to acquire 100,000 preferred units in Augusta, the entity that owned our sponsor’s Augusta facility, for $37,500 in cash and 3,750,000 newly issued convertible Class B units in the Partnership. In connection with this acquisition, the Partnership incurred $451 of acquisition related costs during the year ended December 31, 2013, included in general and administrative expenses.
On April 28, 2014, the Partnership acquired 390,000 common units in Augusta for cash consideration of $224,250. In connection with this acquisition, the Partnership’s preferred equity interest in Augusta was converted into 100,000 common units of Augusta. Following this transaction, the Partnership maintains a 98.0% controlling interest in Augusta’s common units, with the sponsor owning the remaining 2.0% of common units. In connection with this acquisition, the Partnership incurred $768 of acquisition related costs during the year ended December 31, 2014, included in general and administrative expenses.
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. The difference between the consideration paid and the recasted historical cost of the net assets acquired was allocated in accordance with the partnership agreement to the common and subordinated unitholders based on their respective number of units outstanding as of April 28, 2014. However, this deemed distribution did not affect the tax basis capital accounts of the common and subordinated unitholders.
The Partnership's historical financial information was recast to combine the Consolidated Statements of Operations and the Consolidated Balance Sheets of the Partnership with those of Augusta as if the combination had been in effect since inception of common control. Any material transactions between the Partnership and Augusta have been eliminated. The balance of non-controlling interest as of December 31, 2013 represents the sponsor's interest in Augusta prior to the combination. Except for the combination of the Consolidated Statements of Operations and the respective allocation of recasted net income between the controlling and non-controlling interest, capital transactions between the sponsor have not been allocated on a recasted basis to the common and subordinated unitholders. Such transactions are presented within the non-controlling interest column in the Consolidated Statement of Partners' Capital as the Partnership and its unitholders would not have participated in these transactions.
The following table summarizes the carrying value of Augusta's assets as of April 28, 2014, and the allocation of the cash consideration paid:
Net assets of Hi-Crush Augusta LLC as of April 28, 2014:
 
 
Cash
 
$
1,035

Accounts receivable
 
9,816

Inventories
 
4,012

Prepaid expenses and other current assets
 
114

Due from Hi-Crush Partners LP
 
1,756

Property, plant and equipment
 
84,900

Accounts payable
 
(3,379
)
Accrued liabilities and other current liabilities
 
(2,926
)
Due to sponsor
 
(4,721
)
Asset retirement obligation
 
(2,993
)
Total carrying value of Augusta's net assets
 
$
87,614

 
 
 
Allocation of purchase price
 
 
Carrying value of sponsor's non-controlling interest prior to Augusta Contribution
 
$
35,951

Less: Carrying value of 2% of non-controlling interest retained by sponsor
 
(1,752
)
Purchase price allocated to non-controlling interest acquired
 
34,199

Excess purchase price over the historical cost of the acquired non-controlling interest(a)
 
190,051

Cost of Augusta acquisition
 
$
224,250

(a) The deemed distribution attributable to the excess purchase price was allocated to the common and subordinated unitholders based on the respective number of units outstanding as of April 28, 2014.




F-23


The following tables present our recasted revenues, net income and net income attributable to Hi-Crush Partners LP per limited partner unit giving effect to the Augusta Contribution, as reconciled to the revenues, net income and net income attributable to Hi-Crush Partners LP per limited partnership unit of the Partnership.
 
Year Ended December 31, 2014
 
Partnership
 
 
 
 
 
Partnership
 
Historical
 
Augusta
 
Eliminations
 
Recasted
Revenues
$
365,347

 
$
25,356

 
$
(4,156
)
 
$
386,547

Net income (loss)
$
120,484

 
$
11,398

 
$
(7,857
)
 
$
124,025

Net income attributable to Hi-Crush Partners LP per limited partner unit - basic
$
3.09

 
 
 
 
 
$
3.14

 
Year Ended December 31, 2013
 
Partnership
 
 
 
 
 
Partnership
 
Historical
 
Augusta
 
Eliminations
 
Recasted
Revenues
$
141,742

 
$
41,630

 
$
(4,402
)
 
$
178,970

Net income (loss)
$
58,562

 
$
13,681

 
$
(12,199
)
 
$
60,044

Net income attributable to Hi-Crush Partners LP per limited partner unit - basic
$
2.08

 
 
 
 
 
$
2.12

 
Period from August 16, 2012 Through December 31, 2012
 
Partnership
 
 
 
 
 
Partnership
 
Historical
 
Augusta
 
Eliminations
 
Recasted
Revenues
$
28,858

 
$
2,912

 
$

 
$
31,770

Net income (loss)
$
18,508

 
$
(1,091
)
 
$

 
$
17,417

Net income attributable to Hi-Crush Partners LP per limited partner unit - basic
$
0.68

 
 
 
 
 
$
0.64



F-24


10. Long-Term Debt
Long-term debt consisted of the following:
 
December 31,
2014
 
December 31,
2013
Term Loan Credit Facility, net of discounts
$
196,688

 
$

Revolving Credit Facility

 

Prior Credit Facility

 
138,250

Other notes payable
3,676

 

Less: current portion of long-term debt
(2,000
)
 

 
$
198,364

 
$
138,250

Subordinated Promissory Notes
Between May 25, 2011 and July 20, 2012, the sponsor entered into various subordinated promissory notes with certain of its equity investors and their affiliates in an aggregate initial principal amount of $52,167. Borrowings under the subordinated promissory notes bore interest, at the sponsor’s option, at a rate of 10% for cash interest and 12% for paid-in-kind interest (“PIK interest”). Accruals for PIK interest increased the outstanding principal balance of these promissory notes. The balances of the PIK interest and subordinated promissory notes were paid in full on August 21, 2012 with the proceeds of the sale of the common units by the sponsor.
New Subordinated Promissory Notes
In order to fund a royalty termination payment (See Note 15—Commitments and Contingencies), the sponsor entered into new subordinated promissory notes in July 2012 with certain of its equity investors and their affiliates in an aggregate initial principal amount of $14,981. The balances of the PIK interest and subordinated promissory note, as retained by the sponsor, were paid in full by the sponsor on August 21, 2012 with the proceeds of the sale of the common units by the sponsor.
Sponsor Credit Facility
On April 6, 2012, the sponsor entered into a four-year $62,500 secured credit facility (the “Sponsor Credit Facility”) with Amegy Bank, N.A. and a syndicate of other financial institutions (collectively, the “Lending Banks”). The Sponsor Credit Facility consists of the following commitments on the part of the Lending Banks: (1) a $25,000 term loan, (2) a $30,000 advancing term loan commitment (“Tranche B”) and (3) a $7,500 revolving loan commitment (the “Revolving Commitment”). In addition, the Sponsor Credit Facility includes sub-limits for letters of credit and swing line borrowings of up to $5,000 and $2,500, respectively.
Borrowings under the Sponsor Credit Facility bear interest at a floating rate equal to, at the sponsor’s option, either (a) a base rate plus a range of 225 basis points to 325 basis points per annum or (b) a Eurodollar rate, which is based on one-month LIBOR, plus a range of 325 basis points to 425 basis points per annum. The base rate is established as the highest of (i) the U.S. prime rate last quoted by The Wall Street Journal, (ii) the federal funds rate plus 50 basis points or (iii) daily one-month LIBOR plus 100 basis points. The Revolving Commitment and the Tranche B term loan provide for a commitment fee of 0.5% on the unused portion.
After consummation of the IPO on August 16, 2012, our sponsor retained the Sponsor Credit Facility and related borrowings. In addition, as of August 16, 2012, the Sponsor Credit Facility was no longer guaranteed by the subsidiaries contributed to the Partnership. As such, the sponsor’s long-term debt is not reflected on the Partnership’s successor balance sheets.
On August 21, 2012, the sponsor entered into that certain consent and third amendment to the Sponsor Credit Facility, whereby the lending banks, among other things, (i) consented to the consummation of the initial public offering of the Partnership, (ii) released and discharged certain credit parties in connection with the initial public offering.
Revolving Credit Facility
On August 21, 2012, the Partnership entered into a credit agreement (the “Prior Credit Agreement”) providing for a new $100,000 senior secured revolving credit facility (the “Prior Credit Facility”) with a term of four years. In connection with our acquisition of a preferred interest in Augusta, on January 31, 2013, the Partnership entered into a consent and first amendment to the Prior Credit Agreement whereby the Lending Banks, among other things, (i) consented to the amendment and restatement of the partnership agreement of the Partnership and (ii) agreed to amend the Prior Credit Agreement to permit the acquisition by the Partnership of a preferred equity interest in Hi-Crush Augusta LLC. On May 9, 2013, in connection with our acquisition of D&I, the Partnership entered into a commitment increase agreement and second amendment to the Prior Credit Agreement whereby the Lending Banks, among other things, consented to the increase of the aggregate commitments by $100,000 to a total of $200,000 and addition of lenders to the lending bank group. The outstanding balance of the Prior Credit Facility was paid in full on April 15, 2014.



F-25


On April 28, 2014, the Partnership replaced the Prior Credit Facility by entering into an amended and restated credit agreement (the "Revolving Credit Agreement"). The Revolving Credit Agreement is a senior secured revolving credit facility (the "Revolving Credit Facility") that permits aggregate borrowings of up to $150,000, including a $25,000 sublimit for letters of credit and a $10,000 sublimit for swing line loans. The Revolving Credit Facility matures on April 28, 2019.
The Revolving Credit Facility is secured by substantially all assets of the Partnership. In addition, the Partnership's subsidiaries have guaranteed the Partnership's obligations under the Revolving Credit Agreement and have granted to the revolving lenders security interests in substantially all of their respective assets.
Borrowings under the Revolving Credit Agreement bear interest at a rate equal to, at the Partnership's option, either (1) a base rate plus an applicable margin ranging between 1.25% per annum and 2.50% per annum, based upon the Partnership's leverage ratio, or (2) a Eurodollar rate plus an applicable margin ranging between 2.25% per annum and 3.50% per annum, based upon the Partnership's leverage ratio.
The Revolving Credit Agreement contains customary representations and warranties and customary affirmative and negative covenants, including limits or restrictions on the Partnership’s ability to incur liens, incur indebtedness, make certain restricted payments, merge or consolidate and dispose of assets. The Revolving Credit Agreement also requires compliance with customary financial covenants, which are a leverage ratio and minimum interest coverage ratio. In addition, it contains customary events of default that entitle the lenders to cause any or all of the Partnership’s indebtedness under the Revolving Credit Agreement to become immediately due and payable. The events of default (some of which are subject to applicable grace or cure periods), include among other things, non-payment defaults, covenant defaults, cross-defaults to other material indebtedness, bankruptcy and insolvency defaults and material judgment defaults. As of December 31, 2014, we were in compliance with the covenants contained in the Revolving Credit Agreement.
As of December 31, 2014, we had no indebtedness and $143,848 of undrawn borrowing capacity ($150,000, net of $6,152 letter of credit commitments) under our Revolving Credit Facility.
Term Loan Credit Facility
On April 28, 2014, the Partnership entered into a credit agreement (the "Term Loan Credit Agreement") providing for a senior secured term loan credit facility (the “Term Loan Credit Facility”) that permits aggregate borrowings of up to $200,000, which was fully drawn on April 28, 2014. The Term Loan Credit Agreement permits the Partnership, at its option, to add one or more incremental term loan facilities in an aggregate amount not to exceed $100,000. Any incremental term loan facility would be on terms to be agreed among the Partnership, the administrative agent and the lenders who agree to participate in the incremental facility. The maturity date of the Term Loan Credit Facility is April 28, 2021.
The Term Loan Credit Agreement is secured by substantially all assets of the Partnership. In addition, the Partnership’s subsidiaries have guaranteed the Partnership’s obligations under the Term Loan Credit Agreement and have granted to the lenders security interests in substantially all of their respective assets.
Borrowings under the Term Loan Credit Agreement bear interest at a rate equal to, at the Partnership’s option, either (1) a base rate plus an applicable margin of 2.75% per annum or (2) a Eurodollar rate plus an applicable margin of 3.75% per annum, subject to a LIBOR floor of 1.00%.
The Term Loan Credit Agreement contains customary representations and warranties and customary affirmative and negative covenants, including limits or restrictions on the Partnership’s ability to incur liens, incur indebtedness, make certain restricted payments, merge or consolidate and dispose of assets. In addition, it contains customary events of default that entitle the lenders to cause any or all of the Partnership’s indebtedness under the Term Loan Credit Agreement to become immediately due and payable. The events of default (some of which are subject to applicable grace or cure periods), include, among other things, non-payment defaults, covenant defaults, cross-defaults to other material indebtedness, bankruptcy and insolvency defaults and material judgment defaults.
As of December 31, 2014, we had $196,688 indebtedness ($198,500, net of $1,812 of discounts) under our Term Loan Credit Facility, which carried an interest rate of 4.75% as of December 31, 2014.
Other Notes Payable
On October 24, 2014, the Partnership acquired land and underlying frac sand deposits. The Partnership paid cash consideration of $2,500, and issued a three-year promissory note in the amount of $3,676. The three year promissory note accrues interest at a rate equal to the applicable short-term federal rate, which was 0.34% as of December 31, 2014. All principal and accrued interest is due and payable at the end of the three year note term. However, the note may be prepaid on a quarterly basis during the three-year term if sand is extracted, delivered, sold and paid for from the property.
The Partnership did not make any prepayments during the year ended December 31, 2014.




F-26


As of December 31, 2014, future minimum debt repayments are as follows:
Fiscal Year
 
Amount
2015
 
$
2,000

2016
 
2,000

2017
 
5,676

2018
 
2,000

2019
 
2,000

Thereafter
 
186,688

 
 
$
200,364




F-27


11. Equity
As of December 31, 2014, our sponsor owned all 13,640,351 subordinated units, representing a 36.9% ownership interest in the limited partner units. In addition, the sponsor is the owner of our General Partner.
Class B Units
On January 31, 2013, the Partnership issued 3,750,000 subordinated Class B units and paid $37,500 in cash to the sponsor in return for 100,000 preferred equity units in the sponsor’s Augusta facility. The Class B units did not have voting rights or rights to share in the Partnership's periodic earnings, either through participation in its distributions or through an allocation of undistributed earnings or losses. The Class B units were eligible for conversion into common units once the Partnership had, for two consecutive quarters, (i) earned $2.31 per common unit, subordinated unit and Class B unit on an annualized basis and (ii) paid $2.10 per unit in annualized distributions on each common and subordinated unit, or 110% of the current minimum quarterly distribution for a period of two consecutive quarters, and our General Partner has determined, with the concurrence of the conflicts committee of the board of directors of our General Partner, that we are expected to maintain such performance for at least two succeeding quarters. 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, the 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.
Allocations of Net Income
Our partnership agreement contains provisions for the allocation of net income and loss to the unitholders (excluding Class B unitholders) and our General Partner. For purposes of maintaining partner capital accounts, the partnership agreement specifies that items of income and loss shall be allocated among the partners in accordance with their respective percentage ownership interest. Normal allocations according to percentage interests are made after giving effect, if any, to priority income allocations in an amount equal to incentive cash distributions allocated 100% to our General Partner.
Incentive Distribution Rights
Incentive distribution rights represent the right to receive increasing percentages (ranging from 15.0% to 50.0%) of quarterly distributions from operating surplus after minimum quarterly distribution and target distribution levels exceed $0.54625 per unit, per quarter. Our sponsor currently holds the incentive distribution rights, but may transfer these rights at any time.
Distributions
Our partnership agreement sets forth the calculation to be used to determine the amount of cash distributions that our common and subordinated unitholders and sponsor will receive.
Our distributions have been as follows:
Declaration Date
 
Amount Declared Per Unit (a)
 
Record Date
 
Date Paid
 
Amount paid to Common and Subordinated Units
 
Amount paid to Holders of Incentive Distribution Rights
October 19, 2012
 
$
0.2375

(b) 
November 1, 2012
 
November 15, 2012
 
$
6,480

 
$

January 17, 2013
 
$
0.4750

  
February 1, 2013
 
February 15, 2013
 
$
12,961

 
$

April 16, 2013
 
$
0.4750

  
May 1, 2013
 
May 15, 2013
 
$
12,961

 
$

July 17, 2013
 
$
0.4750

  
August 1, 2013
 
August 15, 2013
 
$
13,711

 
$

October 17, 2013
 
$
0.4900

 
November 1, 2013
 
November 15, 2013
 
$
14,144

 
$

January 15, 2014
 
$
0.5100

 
January 31, 2014
 
February 14, 2014
 
$
14,726

 
$

April 16, 2014
 
$
0.5250

 
May 1, 2014
 
May 15, 2014
 
$
17,388

 
$

July 16, 2014
 
$
0.5750

 
August 1, 2014
 
August 15, 2014
 
$
19,088

 
$
168

October 15, 2014
 
$
0.6250

 
October 31, 2014
 
November 14, 2014
 
$
23,092

 
$
695

January 15, 2015
 
$
0.6750

 
January 30, 2015
 
February 13, 2015
 
$
24,943

 
$
1,311

(a) For all common and subordinated units.
(b) Represents a pro rata distribution of our minimum quarterly distribution for the period from August 16, 2012 through September 30, 2012.




F-28


Net Income per Limited Partner Unit
The following table outlines our basic and diluted, weighted average limited partner units outstanding during the relevant periods:
 
For the Year Ended December 31, 2014
 
For the Year Ended December 31, 2013
 
Period From August 16 Through December 31, 2012
Weighted average limited partner units outstanding:
 
 
 
 
 
Common units - basic
19,729,669

 
14,527,914

 
13,640,351

Subordinated units - basic
13,640,351

 
13,640,351

 
13,640,351

Common units - diluted
22,143,189

 
14,527,914

 
13,640,351

Subordinated units - diluted
13,640,351

 
13,640,351

 
13,640,351

For purposes of calculating the Partnership’s earnings per unit under the two-class method, common units are treated as participating preferred units, and subordinated units are treated as the residual equity interest, or common equity. Incentive distribution rights are treated as participating securities. As the Class B units did not have rights to share in the Partnership’s periodic earnings, whether through participation in its distributions or through an allocation of its undistributed earnings or losses, they were not participating securities. In addition, the conversion of the Class B units into common units was fully contingent upon the satisfaction of defined criteria pertaining to the cumulative payment of distributions and earnings per unit of the Partnership as described in this Note 11. As such, until all of the defined payment and earnings criteria were satisfied, the Class B units were not included in our calculation of either basic or diluted earnings per unit. The Class B units were converted into common units on August 15, 2014, at which time income allocations commenced on such units. The sponsor was entitled to receive a per unit distribution on the newly converted common units for the second quarter of 2014 in an amount equal to the per unit distribution to be paid to all the common and subordinated units for the same period. As a result, this distribution was deducted from the calculation of limited partners' interest in net income for the year ended December 31, 2014. In addition, the Class B units were included in our calculation of diluted earnings per unit through August 15, 2014. Diluted earnings per unit for the year ended December 31, 2014 also includes the dilutive effect of LTIP awards granted in June 2014 (see Note 12 - Unit Based Compensation) at the assumed number of units which would have vested if the performance period had ended on December 31, 2014.
Distributions made in future periods based on the current period calculation of cash available for distribution are allocated to each class of equity that will receive such distributions. Any unpaid cumulative distributions are allocated to the appropriate class of equity. 
Each period the Partnership determines the amount of cash available for distributions in accordance with the partnership agreement. The amount to be distributed to common unitholders, subordinated unitholders and incentive distribution rights holders is based on the distribution waterfall in the partnership agreement. Net earnings for the period are allocated to each class of partnership interest based on the distributions to be made. Additionally, if, during the subordination period, the Partnership does not have enough cash available to make the required minimum distribution to the common unit holders, the Partnership will allocate net earnings to the common unit holders based on the amount of distributions in arrears. When actual cash distributions are made based on distributions in arrears, those cash distributions will not be allocated to the common unitholders, as such earnings were allocated in previous periods.














F-29


The following table provides a reconciliation of net income and the assumed allocation of net income under the two-class method for purposes of computing net income per unit for the year ended December 31, 2014 (in thousands, except per unit amounts):
 
General Partner and IDRs
 
Common Units
 
Subordinated Units
 
Class B Units
 
Total
Declared distribution
$
2,174

 
$
51,774

 
$
32,737

 
$
2,156

 
$
88,841

Assumed allocation of undistributed net income attributable to the Partnership
12,367

 
9,268

 
9,465

 

 
31,100

Limited partners’ interest in net income
$
14,541

 
$
61,042

 
$
42,202

 
$
2,156

 
$
119,941

Recast adjustments to include the results of operations of Hi-Crush Augusta LLC and income attributable to non-controlling interest
 
 
 
 
 
 
 
 
3,129

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

Earnings per unit - basic
 
 
$
3.09

 
$
3.09

 
 
 
 
Earnings per unit - diluted (1)
 
 
$
3.00

 
$
3.00

 
 
 
 
(1) Diluted earnings per unit includes the impact of income allocations attributable to a conversion of the Class B units into common units through conversion to common units on August 15, 2014.
Recasted Augusta Equity Transactions
As of August 16, 2012, the Partnership recognized a capital contribution of $1,035 equal to Augusta's net assets at inception of common control. This capital contribution was allocated 98.0% to the Partnership's unit holders and 2.0% to non-controlling interest for purposes of recasting the historical financial information to include Augusta.
During the year ended December 31, 2013, the sponsor provided $1,424 of management services and other expenses paid on behalf of Augusta. Such costs are recognized as non-cash capital contributions by the non-controlling interest in the accompanying financial statements.
On January 31, 2013, Augusta converted $38,172 of certain payables owed to the sponsor into capital and paid a cash distribution of $4,637 to the sponsor. Such transactions are recognized within the non-controlling interest section of the accompanying Statement of Partners' Capital.
During the year ended December 31, 2014, the sponsor provided $492 of management services and other expenses paid on behalf of Augusta. Such costs are recognized as non-cash capital contributions by the non-controlling interest in the accompanying financial statements.



F-30


12. Unit Based Compensation
Long-Term Incentive Plan
On August 21, 2012, Hi-Crush GP LLC adopted the Hi-Crush Partners LP Long Term Incentive Plan (the “Plan”) for employees, consultants and directors of Hi-Crush GP LLC and those of its affiliates, including our sponsor, who perform services for the Partnership. The Plan consists of restricted units, unit options, phantom units, unit payments, unit appreciation rights, other equity-based awards, distribution equivalent rights and performance awards. The Plan limits the number of common units that may be issued pursuant to awards under the Plan to 1,364,035 units. Common units withheld to satisfy exercise prices or tax withholding obligations are available for delivery pursuant to other awards. The Plan is administered by Hi-Crush GP LLC’s board of directors or a committee thereof.
The cost of services received in exchange for an award of equity instruments is measured based on the grant-date fair value of the award and that cost is generally recognized over the vesting period of the award.
Performance Phantom Units - Equity Settled
The Partnership has awarded Performance Phantom Units ("PPUs") pursuant to the Plan to certain employees. The number of PPUs that will vest will range from 0% to 200% of the number of initially granted PPUs and is dependent on the Partnership's total unitholder return over a three-year performance period compared to the total unitholder return of a designated peer group. Each PPU represents the right to receive, upon vesting, one common unit representing limited partner interests in the Partnership. The PPUs are also entitled to forfeitable distribution equivalent rights ("DERs"), which accumulate during the performance period and are paid in cash on the date of settlement. The fair value of each PPU is estimated using a fair value approach and is amortized into compensation expense, reduced for an estimate of expected forfeitures, over the period of service corresponding with the vesting period. Expected volatility is based on the historical market performance of our peer group. The following table presents information relative to our PPUs.
 
 
 
Grant Date
 
 
 
Weighted -
 
 
 
Average Fair
 
Units
 
Value per Unit
Outstanding at January 1, 2014

 
 
Granted
64,414

 
$
65.57

Forfeited

 

Outstanding at December 31, 2014
64,414

 
$
65.57

As of December 31, 2014, total compensation expense not yet recognized related to unvested PPUs was $3,269, with a weighted average remaining service period of 2 years.
Time-Based Phantom Units - Equity Settled
The Partnership has awarded Time-Based Phantom Units ("TPUs") pursuant to the Plan to certain employees which automatically vest if the employee remains employed at the end of a three-year vesting period. Each TPU represents the right to receive, upon vesting, one common unit representing limited partner interests in the Partnership. The TPUs are also entitled to forfeitable DERs, which accumulate during the vesting period and are paid in cash on the date of settlement. The fair value of each TPU is calculated based on the grant-date unit price and is amortized into compensation expense, reduced for an estimate of expected forfeitures, over the period of service corresponding with the vesting period. The following table presents information relative to our TPUs.
 
 
 
Grant Date
 
 
 
Weighted -
 
 
 
Average Fair
 
Units
 
Value per Unit
Outstanding at January 1, 2014

 
 
Granted
17,018

 
$
47.33

Forfeited
(415
)
 
$
47.33

Outstanding at December 31, 2014
16,603

 
$
47.33

As of December 31, 2014, total compensation expense not yet recognized related to unvested TPUs was $650, with a weighted average remaining service period of 2.5 years.
Board and Other Unit Grants
The Partnership issued 5,532 and 5,522 common units to its independent directors during the years ended December 31, 2014 and 2013, respectively. During the year ended December 31, 2014, the Partnership issued 7,022 common units to certain employees which vest approximately over a 2 year period.


F-31


Compensation Expense
The following table presents total compensation expense for unit-based compensation:
 
For the Year Ended December 31, 2014
 
For the Year Ended December 31, 2013
 
Period From August 16 Through December 31, 2012
Performance Phantom Units
$
954

 
$

 
$

Time-based Phantom Units
155

 

 

Director and other unit grants
361

 
100

 

Total compensation expense
$
1,470

 
$
100

 
$



F-32


13. Related Party Transactions
On May 25, 2011, the sponsor entered into a management services agreement with Red Oak Capital Management LLC (the “Service Provider”) which is owned by two members who are also equity members in the sponsor. The agreement provides for certain management and administrative support services to be provided to the sponsor for a term of one year and that thereafter remains in place upon the same terms and conditions. Either party may terminate the agreement by delivering written notice within 90 days prior to the date of expiration of the initial term or any time after the expiration of the initial term, by delivering written notice 90 days prior to the desired date of termination. The sponsor reimburses the Service Provider 95% of the Service Provider’s actual costs limited to $850 per year. Total fees were $166 during the period from August 16 through December 31, 2012 and $318 for the period from January 1 through August 15, 2012. These fees are included in general and administrative expenses. Management fees incurred during the years ended December 31, 2014 and 2013 are included as a portion of the management services expense from Hi-Crush Services, as discussed below.
The sponsor paid quarterly director fees to non-management directors that may be members and/or holders of the sponsor’s debt through the date of the IPO. Total fees were $62 for the period from January 1 through August 15, 2012.
During the years ended December 31, 2014 and 2013 and the period from August 16 through December 31, 2012, the Partnership incurred $9,421, $5,122 and $1,702, respectively, of management service expenses from Hi-Crush Services under the Services Agreement discussed in Note 4.
In the normal course of business, our sponsor and its affiliates, including Hi-Crush Services, and the Partnership may from time to time make payments on behalf of each other. During the period from August 16 through December 31, 2012, we made payments of $9,866 to various suppliers, vendors or other counterparties on behalf of our sponsor. This balance was offset by $1,028 of management fees charged by our sponsor and $3,223 of net payments made by our sponsor on behalf of us. The balance of $5,615 was repaid by our sponsor in February 2013.
During the year ended December 31, 2014, the Partnership purchased $23,705 of sand from Hi-Crush Whitehall LLC, a subsidiary of our sponsor and the entity that owns the sponsor's Whitehall facility, at a purchase price in excess of our production cost per ton.
During the year ended December 31, 2014, the Partnership purchased $1,385 of sand from Goose Landing, LLC, a wholly owned subsidiary of Northern Frac Proppants II, LLC. The father of Mr. Alston, who is our general partner's Chief Operating Officer, owns a controlling equity interest in Northern Frac Proppants II, LLC. Although we acquired the sand at a purchase price in excess of our production cost per ton, the terms of the purchase price were the result of arm's length negotiations.
As of December 31, 2014 and 2013, an outstanding balance of $13,459 and $10,352, respectively, payable to our sponsor is maintained as a current liability under the caption “Due to sponsor”.
In connection with the acquisition of the preferred interest in Hi-Crush Augusta LLC, on January 31, 2013, our sponsor extinguished balances owed by Hi-Crush Augusta LLC as follows:
Conversion into common units of Hi-Crush Augusta LLC, representing a non-controlling interest in the Partnership
$
38,172

Conversion into preferred units of Hi-Crush Augusta LLC
9,543

Assumption of bank debt
33,250

Total payable to sponsor extinguished
$
80,965


F-33


14. Segment Reporting
The Partnership manages, operates and owns assets utilized to supply frac sand to its customers. It conducts operations through its one operating segment titled "Frac Sand Sales" for reporting purposes. This reporting segment of the Partnership is evaluated regularly by the chief operating decision maker in deciding how to allocate resources and in assessing performance.

F-34


15. Commitments and Contingencies
The Partnership enters into sales contracts with customers. These contracts establish minimum annual sand volumes that the Partnership is required to make available to such customers under initial terms ranging from 3 to 6 years. Through December 31, 2014, no payments for non-delivery of minimum annual sand volumes have been made by the Partnership to these customers under these contracts.
D&I has entered into long-term supply agreements with certain of its suppliers which include requirements to purchase certain volumes and grades of sands, at specified prices. The quantities set forth in such agreements are not in excess of our current requirements.

The Partnership has entered into royalty agreements under which the Partnership is under a commitment to pay royalties on sand sold from the Wyeville and Augusta facilities for which the Partnership has received payment by the customer. Royalty expense is recorded as the sand is sold and the royalty payment is paid based on sand volumes sold and paid for by the customer. Royalty expense is included in costs of goods sold. Royalty expense was $3,795 for the Predecessor period from January 1 through August 15, 2012. Royalty expense was $14,583, $8,329 and $1,203 for the Successor years ended December 31, 2014 and 2013 and the period of August 16 to December 31, 2012, respectively.
On July 13, 2012, the sponsor paid $14,000 in cash to terminate one of its existing royalty agreements, including $370 of outstanding obligations at the time. As a result of this payment, the Partnership is no longer required to make ongoing future royalty payments to the applicable counterparties for each ton of frac sand that is excavated, processed and sold to the Partnership’s customers. As part of this transaction, the Predecessor recorded an asset of $13,630 in property, plant and equipment.
On October 24, 2014, the Partnership entered into a purchase and sale agreement to acquire certain tracts of land and specific quantities of the underlying frac sand deposits. The transaction includes three separate tranches of land and deposits, to be acquired over a three year period from 2014 through 2016. During 2014, the Partnership acquired the first tranche of land for $6,176. As of December 31, 2014, the Partnership has committed to purchase the remaining two tranches during 2015 and 2016 for total consideration of $12,352.
The Partnership has long-term operating leases for rail access, railcars and equipment at its terminal sites, which are also under long-term lease agreements with various railroads and other counterparties. Railcar rental expense was $10,438 and $2,035 for the years ended December 31, 2014 and 2013. As of December 31, 2014, future minimum operating lease payments are as follows:
Fiscal Year
 
Amount
2015
 
$
16,893

2016
 
16,017

2017
 
15,717

2018
 
14,710

2019
 
11,668

Thereafter
 
5,383

 
 
$
80,388

From time to time the Partnership may be subject to various claims and legal proceedings which arise in the normal course of business. Management is not aware of any legal matters that are likely to have a material adverse effect on the Partnership’s financial position, results of operations or cash flows.






F-35


16. Asset Retirement Obligation
Although the ultimate amount of reclamation and closure costs to be incurred is uncertain, the Partnership maintained a post-closure reclamation and site restoration obligation as follows:
Balance at January 1, 2012
$
832

Additions to liabilities
3,449

Accretion expense from January 1 to August 15, 2012
16

Accretion expense from August 16 to December 31, 2012
102

Balance at December 31, 2012
4,399

Additions to liabilities

Accretion expense
228

Balance at December 31, 2013
4,627

Additions to liabilities
1,857

Accretion expense
246

Balance at December 31, 2014
$
6,730


F-36


17. Quarterly Financial Data (Unaudited)
 
 
First
Quarter
 
Second
Quarter
 
Third
Quarter (1)
 
Fourth
Quarter
 
Total
2014
 
Successor
 
Successor
 
Successor
 
Successor
 
Successor
Revenues
 
$
70,578

 
$
82,724

 
$
102,316

 
$
130,929

 
$
386,547

Gross profit
 
26,412

 
38,865

 
46,676

 
48,610

 
160,563

Income from operations
 
19,930

 
32,120

 
40,432

 
41,489

 
133,971

Net income
 
18,520

 
29,805

 
37,321

 
38,379

 
124,025

Earnings per unit – common units (basic)
 
$
0.49

 
$
0.77

 
$
0.86

 
$
0.85

 
$
3.09

Earnings per unit – subordinated units (basic)
 
$
0.49

 
$
0.77

 
$
0.86

 
$
0.85

 
$
3.09

 
 
 
 
 
 
 
 
 
 
 
2013
 
Successor
 
Successor
 
Successor
 
Successor
 
Successor
Revenues
 
$
24,277

 
$
37,560

 
$
53,158

 
$
63,975

 
$
178,970

Gross profit
 
15,357

 
19,736

 
21,289

 
26,704

 
83,086

Income from operations
 
11,991

 
15,151

 
15,690

 
20,883

 
63,715

Net income
 
11,677

 
14,437

 
14,417

 
19,513

 
60,044

Earnings per unit – common units (basic)
 
$
0.40

 
$
0.53

 
$
0.52

 
$
0.63

 
$
2.08

Earnings per unit – subordinated units (basic)
 
$
0.40

 
$
0.53

 
$
0.52

 
$
0.63

 
$
2.08

 
 
 
 
 
 
 
 
 
 
 
2012
 
Predecessor
 
Predecessor
 
Pro Forma
 
Successor
 
Pro Forma
Revenues
 
$
13,532

 
$
20,643

 
$
25,330

 
$
19,041

 
$
78,546

Gross profit
 
8,756

 
15,149

 
18,773

 
12,479

 
55,157

Income from operations
 
7,067

 
13,269

 
16,423

 
9,232

 
45,991

Net income
 
6,137

 
11,814

 
15,483

 
9,003

 
42,437

Earnings per unit – common units (basic) (2)
 
 
 
 
 
$
0.33

 
$
0.35

 
$
0.68

Earnings per unit – subordinated units (basic) (2)
 
 
 
 
 
$
0.33

 
$
0.35

 
$
0.68

(1)
The results for the third quarter ended September 30, 2012 include those of our predecessor (July 1 to August 15) combined with the successor (August 16 to September 30).
(2)
Earnings per unit was only calculated for periods subsequent to the August 16, 2012 initial public offering.
The following table reconciles our pro forma quarterly results for the third quarter ended September 30, 2012, to our predecessor and successor period results during that quarter.
 
Period from July 1 Through August 15, 2012
 
Period from August 16 Through September 30, 2012
 
Total
 
Predecessor
 
Successor
 
Pro Forma
Revenues
$
12,601

 
$
12,729

 
$
25,330

Gross profit
9,536

 
9,237

 
18,773

Income from operations
7,918

 
8,505

 
16,423

Net income
7,069

 
8,414

 
15,483

Earnings per unit – common units
 
 
$
0.33

 
$
0.33

Earnings per unit – subordinated units
 
 
$
0.33

 
$
0.33


F-37


18. Condensed Consolidating Financial Information
The Partnership has filed a registration statement on Form S-3 to register, among other securities, debt securities. Each of the subsidiaries of the Partnership as of March 31, 2014 (other than Hi-Crush Finance Corp., whose sole purpose is to act as a co-issuer of any debt securities) was a 100% directly or indirectly owned subsidiary of the Partnership (the “guarantors”), will issue guarantees of the debt securities, if any of them issue guarantees, and such guarantees will be full and unconditional and will constitute the joint and several obligations of such guarantors. As of December 31, 2014, the guarantors were our sole subsidiaries, other than: Hi-Crush Finance Corp., Hi-Crush Augusta Acquisition Co. LLC, Hi-Crush Canada Inc. and Hi-Crush Canada Distribution Corp., which are 100% owned subsidiaries, and Hi-Crush Augusta LLC, of which we own 98% of the common equity interest.
As of December 31, 2014, the Partnership had no assets or operations independent of its subsidiaries, and there were no significant restrictions upon the ability of the Partnership or any of its subsidiaries to obtain funds from its respective subsidiaries by dividend or loan. As of December 31, 2014, none of the assets of our subsidiaries represented restricted net assets pursuant to Rule 4-08(e)(3) of Regulation S-X under the Securities Act.
For the purpose of the following financial information, the Partnership's investments in its subsidiaries are presented in accordance with the equity method of accounting. The operations, cash flows and financial position of the co-issuer are not material and therefore have been included with the parent's financial information.
Condensed consolidating financial information for the Partnership and its combined guarantor and combined non-guarantor subsidiaries is as follows for the dates and periods indicated.























F-38



Condensed Consolidating Balance Sheet
As of December 31, 2014
 
Parent
 
Guarantor Subsidiaries
 
Non-Guarantor Subsidiaries
 
Consolidating Adjustments
 
Consolidated
Assets
 
 
 
 
 
 
 
 
 
Current assets:
 
 
 
 
 
 
 
 
 
Cash
$
308

 
$
3,490

 
$
848

 
$

 
$
4,646

Restricted cash

 
691

 

 

 
691

Accounts receivable

 
71,504

 
10,613

 

 
82,117

Intercompany receivables
88,621

 
120,401

 

 
(209,022
)
 

Inventories

 
18,828

 
6,521

 
(1,665
)
 
23,684

Prepaid expenses and other current assets
277

 
3,802

 
2

 

 
4,081

Total current assets
89,206

 
218,716

 
17,984

 
(210,687
)
 
115,219

Property, plant and equipment, net
23

 
136,240

 
105,062

 

 
241,325

Goodwill and intangible assets, net

 
66,750

 

 

 
66,750

Investment in consolidated affiliates
277,343

 

 
224,250

 
(501,593
)
 

Other assets
7,511

 
5,315

 

 

 
12,826

Total assets
$
374,083

 
$
427,021

 
$
347,296

 
$
(712,280
)
 
$
436,120

Liabilities, Equity and Non-Controlling Interest
 
 
 
 
 
 
 
 
 
Current liabilities:
 
 
 
 
 
 
 
 
 
Accounts payable
$
151

 
$
21,401

 
$
3,326

 
$

 
$
24,878

Accrued and other current liabilities
513

 
6,236

 
5,499

 

 
12,248

Intercompany payables

 

 
209,021

 
(209,021
)
 

Due to sponsor
769

 
11,978

 
712

 

 
13,459

Current portion of long-term debt
2,000

 

 

 

 
2,000

Total current liabilities
3,433

 
39,615

 
218,558

 
(209,021
)
 
52,585

Long-term debt
194,688

 
3,676

 

 

 
198,364

Asset retirement obligation

 
1,799

 
4,931

 

 
6,730

Total liabilities
198,121

 
45,090

 
223,489

 
(209,021
)
 
257,679

Commitments and contingencies

 

 

 

 

Equity and Non-Controlling Interest:
 
 
 
 
 
 
 
 
 
Equity
175,962

 
381,931

 
121,328

 
(503,259
)
 
175,962

Non-controlling interest

 

 
2,479

 

 
2,479

Total equity and non-controlling interest
175,962

 
381,931

 
123,807

 
(503,259
)
 
178,441

Total liabilities, equity and non-controlling interest
$
374,083

 
$
427,021

 
$
347,296

 
$
(712,280
)
 
$
436,120












F-39



Condensed Consolidating Balance Sheet
As of December 31, 2013
 
Parent
 
Guarantor Subsidiaries
 
Non-Guarantor Subsidiaries
 
Consolidating Adjustments
 
Consolidated
Assets
 
 
 
 
 
 
 
 
 
Current assets:
 
 
 
 
 
 
 
 
 
Cash
$
12,056

 
$
3,991

 
$
4,561

 
$

 
$
20,608

Restricted cash

 
690

 

 

 
690

Accounts receivable

 
31,581

 
5,861

 

 
37,442

Intercompany receivables

 
54,468

 
1,311

 
(55,779
)
 

Inventories

 
16,265

 
7,102

 
(949
)
 
22,418

Prepaid expenses and other current assets
573

 
859

 
193

 

 
1,625

Total current assets
12,629

 
107,854

 
19,028

 
(56,728
)
 
82,783

Property, plant and equipment, net
7

 
113,335

 
82,492

 

 
195,834

Goodwill and intangible assets, net

 
71,936

 

 

 
71,936

Investment in consolidated affiliates
329,604

 

 

 
(329,604
)
 

Other assets
1,467

 
2,341

 

 

 
3,808

Total assets
$
343,707

 
$
295,466

 
$
101,520

 
$
(386,332
)
 
$
354,361

Liabilities, Equity and Non-Controlling Interest
 
 
 
 
 
 
 
 
 
Current liabilities:
 
 
 
 
 
 
 
 
 
Accounts payable
$
219

 
$
8,087

 
$
1,802

 
$

 
$
10,108

Accrued and other current liabilities
459

 
3,917

 
3,293

 

 
7,669

Intercompany payables
55,779

 

 

 
(55,779
)
 

Due to sponsor
877

 
382

 
9,093

 

 
10,352

Total current liabilities
57,334

 
12,386

 
14,188

 
(55,779
)
 
28,129

Long-term debt
138,250

 

 

 

 
138,250

Asset retirement obligation

 
1,673

 
2,955

 

 
4,628

Total liabilities
195,584

 
14,059

 
17,143

 
(55,779
)
 
171,007

Commitments and contingencies

 

 

 

 

Equity and Non-Controlling Interest:
 
 
 
 
 
 
 
 
 
Equity
148,123

 
281,407

 
49,146

 
(330,553
)
 
148,123

Non-controlling interest

 

 
35,231

 

 
35,231

Total equity and non-controlling interest
148,123

 
281,407

 
84,377

 
(330,553
)
 
183,354

Total liabilities, equity and non-controlling interest
$
343,707

 
$
295,466

 
$
101,520

 
$
(386,332
)
 
$
354,361



















F-40


Condensed Consolidating Statements of Operations
For the Year Ended December 31, 2014 (Successor)
 
Parent
 
Guarantor Subsidiaries
 
Non-Guarantor Subsidiaries
 
Consolidating Adjustments
 
Consolidated
Revenues
$

 
$
336,463

 
$
89,208

 
$
(39,124
)
 
$
386,547

Cost of goods sold (including depreciation, depletion and amortization)

 
225,728

 
39,523

 
(39,267
)
 
225,984

Gross profit

 
110,735

 
49,685

 
143

 
160,563

Operating costs and expenses:
 
 
 
 
 
 
 
 
 
General and administrative expenses
13,624

 
10,883

 
1,839

 

 
26,346

Exploration expense

 

 

 

 

Accretion of asset retirement obligation

 
126

 
120

 

 
246

Income (loss) from operations
(13,624
)
 
99,726

 
47,726

 
143

 
133,971

Other income (expense):
 
 
 
 
 
 
 
 
 
Earnings from consolidated affiliates
146,444

 

 

 
(146,444
)
 

Interest expense
(9,750
)
 
(62
)
 
(134
)
 

 
(9,946
)
Net income (loss)
123,070

 
99,664

 
47,592

 
(146,301
)
 
124,025

Income attributable to non-controlling interest

 

 
(955
)
 

 
(955
)
Net income (loss) attributable to Hi-Crush Partners LP
$
123,070

 
$
99,664

 
$
46,637

 
$
(146,301
)
 
$
123,070


For the Year Ended December 31, 2013 (Successor)
 
Parent
 
Guarantor Subsidiaries
 
Non-Guarantor Subsidiaries
 
Consolidating Adjustments
 
Consolidated
Revenues
$

 
$
141,742

 
$
41,630

 
$
(4,402
)
 
$
178,970

Cost of goods sold (including depreciation, depletion and amortization)

 
74,539

 
24,798

 
(3,453
)
 
95,884

Gross profit

 
67,203

 
16,832

 
(949
)
 
83,086

Operating costs and expenses:
 
 
 
 
 
 
 
 
 
General and administrative expenses
9,729

 
6,476

 
2,891

 

 
19,096

Exploration expense

 
47

 

 

 
47

Accretion of asset retirement obligation

 
117

 
111

 

 
228

Income (loss) from operations
(9,729
)
 
60,563

 
13,830

 
(949
)
 
63,715

Other income (expense):
 
 
 
 
 
 
 
 
 
Earnings from consolidated affiliates
72,984

 

 

 
(72,984
)
 

Interest expense
(3,485
)
 
(37
)
 
(149
)
 

 
(3,671
)
Net income
59,770

 
60,526

 
13,681

 
(73,933
)
 
60,044

Income attributable to non-controlling interest

 

 
(274
)
 

 
(274
)
Net income attributable to Hi-Crush Partners LP
$
59,770

 
$
60,526

 
$
13,407

 
$
(73,933
)
 
$
59,770



F-41


For the Period From August 16, 2012 Through December 31, 2012 (Successor)
 
Parent
 
Guarantor Subsidiaries
 
Non-Guarantor Subsidiaries
 
Consolidating Adjustments
 
Consolidated
Revenues
$

 
$
28,858

 
$
2,912

 
$

 
$
31,770

Cost of goods sold (including depreciation, depletion and amortization)

 
7,145

 
2,908

 

 
10,053

Gross profit

 
21,713

 
4

 

 
21,717

Operating costs and expenses:
 
 
 
 
 
 
 
 
 
General and administrative expenses
2,107

 
689

 
961

 

 
3,757

Exploration expense

 
91

 
30

 

 
121

Accretion of asset retirement obligation

 
56

 
46

 

 
102

Income (loss) from operations
(2,107
)
 
20,877

 
(1,033
)
 

 
17,737

Other income (expense):
 
 
 
 
 
 
 
 
 
Earnings from consolidated affiliates
19,788

 

 

 
(19,788
)
 

Interest expense
(241
)
 
(22
)
 
(57
)
 

 
(320
)
Net income
17,440

 
20,855

 
(1,090
)
 
(19,788
)
 
17,417

Income attributable to non-controlling interest

 

 
23

 

 
23

Net income (loss) attributable to Hi-Crush Partners LP
$
17,440

 
$
20,855

 
$
(1,067
)
 
$
(19,788
)
 
$
17,440

For the Period From January 1, 2012 Through Augusta 15, 2012 (Predecessor)
 
Parent
 
Guarantor Subsidiaries
 
Non-Guarantor Subsidiaries
 
Consolidating Adjustments
 
Consolidated
Revenues
$

 
$
46,506

 
$
270

 
$

 
$
46,776

Cost of goods sold (including depreciation, depletion and amortization)

 
12,873

 
463

 

 
13,336

Gross profit (loss)

 
33,633

 
(193
)
 

 
33,440

Operating costs and expenses:
 
 
 
 
 
 
 
 
 
General and administrative expenses
132

 
2,074

 
2,425

 

 
4,631

Exploration expense

 
16

 
523

 

 
539

Accretion of asset retirement obligation

 
16

 

 

 
16

Income (loss) from operations
(132
)
 
31,527

 
(3,141
)
 

 
28,254

Other income (expense):
 
 
 
 
 
 
 
 
 
Earnings from consolidated affiliates
25,152

 

 

 
(25,152
)
 

Other income

 

 
6

 

 
6

Interest expense

 

 
(3,240
)
 

 
(3,240
)
Net income (loss)
25,020

 
31,527

 
(6,375
)
 
(25,152
)
 
25,020

Income attributable to non-controlling interest

 

 

 

 

Net income (loss) attributable to Hi-Crush Partners LP
$
25,020

 
$
31,527

 
$
(6,375
)
 
$
(25,152
)
 
$
25,020
















F-42


Condensed Consolidating Statements of Cash Flows
For the Year Ended December 31, 2014 (Successor)
 
Parent
 
Guarantor Subsidiaries
 
Non-Guarantor Subsidiaries
 
Consolidating Adjustments
 
Consolidated
Net cash provided by operating activities
$
68,139

 
$
82,840

 
$
41,895

 
$
(88,504
)
 
$
104,370

Investing activities:
 
 
 
 
 
 
 
 
 
Cash paid for acquisition of Hi-Crush Augusta LLC

 

 
(224,250
)
 

 
(224,250
)
Capital expenditures for property, plant and equipment
(20
)
 
(15,191
)
 
(25,254
)
 

 
(40,465
)
Net cash used in investing activities
(20
)
 
(15,191
)
 
(249,504
)
 

 
(264,715
)
Financing activities:
 
 
 
 
 
 
 
 
 
Proceeds from equity issuance
170,693

 

 

 

 
170,693

Proceeds from issuance of long-term debt
198,000

 

 

 

 
198,000

Repayment of long-term debt
(139,750
)
 

 

 

 
(139,750
)
Advances to parent, net
(224,250
)
 
(68,150
)
 
212,550

 
79,850

 

Loan origination costs
(7,120
)
 

 

 

 
(7,120
)
Redemption of common units
(19
)
 

 

 

 
(19
)
Distributions paid
(77,421
)
 

 
(8,654
)
 
8,654

 
(77,421
)
Net cash provided by (used in) financing activities
(79,867
)
 
(68,150
)
 
203,896

 
88,504

 
144,383

Net increase (decrease) in cash
(11,748
)
 
(501
)
 
(3,713
)
 

 
(15,962
)
Cash:
 
 
 
 
 
 
 
 
 
Beginning of period
12,056

 
3,991

 
4,561

 

 
20,608

End of period
$
308

 
$
3,490

 
$
848

 
$

 
$
4,646


For the Year Ended December 31, 2013 (Successor)
 
Parent
 
Guarantor Subsidiaries
 
Non-Guarantor Subsidiaries
 
Consolidating Adjustments
 
Consolidated
Net cash provided by operating activities
$
55,252

 
$
44,503

 
$
11,476

 
$
(46,908
)
 
$
64,323

Investing activities:
 
 
 
 
 
 
 
 
 
Investment in Hi-Crush Augusta LLC
(37,500
)
 

 

 
37,500

 

Cash paid for acquisition of D&I Silica, LLC
(94,955
)
 

 

 

 
(94,955
)
Capital expenditures for property, plant and equipment

 
(6,260
)
 
(4,370
)
 

 
(10,630
)
Net cash used in investing activities
(132,455
)
 
(6,260
)
 
(4,370
)
 
37,500

 
(105,585
)
Financing activities:
 
 
 
 
 
 
 
 
 
Proceeds from issuance of long-term debt
138,250

 

 

 

 
138,250

Repayment of long-term debt

 

 
(33,250
)
 

 
(33,250
)
Affiliate financing, net
5,615

 

 
9,092

 
(9,092
)
 
5,615

Advances to parent, net

 
(44,750
)
 

 
44,750

 

Issuance of preferred units to parent

 

 
37,500

 
(37,500
)
 

Loan origination costs
(829
)
 

 

 

 
(829
)
Distributions paid
(53,777
)
 

 
(15,887
)
 
11,250

 
(58,414
)
Net cash provided by (used in) financing activities
89,259

 
(44,750
)
 
(2,545
)
 
9,408

 
51,372

Net increase (decrease) in cash
12,056

 
(6,507
)
 
4,561

 

 
10,110

Cash:
 
 
 
 
 
 
 
 
 
Beginning of period

 
10,498

 

 

 
10,498

End of period
$
12,056

 
$
3,991

 
$
4,561

 
$

 
$
20,608



F-43


For the Period From August 16, 2012 Through December 31, 2012 (Successor)
 
Parent
 
Guarantor Subsidiaries
 
Non-Guarantor Subsidiaries
 
Consolidating Adjustments
 
Consolidated
Net cash provided by (used in) operating activities
$
7,631

 
$
10,753

 
$
(3,886
)
 
$

 
$
14,498

Investing activities:
 
 
 
 
 
 
 
 
 
Capital expenditures for property, plant and equipment

 
(2,239
)
 
(5,979
)
 

 
(8,218
)
Net cash used in investing activities

 
(2,239
)
 
(5,979
)
 

 
(8,218
)
Financing activities:
 
 
 
 
 
 
 
 
 
Affiliate financing, net
(5,615
)
 

 
9,865

 

 
4,250

Contributions received
4,606

 

 

 

 
4,606

Loan origination costs
(143
)
 

 

 

 
(143
)
Distributions paid
(6,479
)
 

 

 

 
(6,479
)
Net cash provided by (used in) financing activities
(7,631
)
 

 
9,865

 

 
2,234

Net increase in cash

 
8,514

 

 

 
8,514

Cash:
 
 
 
 
 
 
 
 
 
Beginning of period

 
1,984

 

 

 
1,984

End of period
$

 
$
10,498

 
$

 
$

 
$
10,498

For the Period From January 1, 2012 Through Augusta 15, 2012 (Predecessor)
 
Parent
 
Guarantor Subsidiaries
 
Non-Guarantor Subsidiaries
 
Consolidating Adjustments
 
Consolidated
Net cash provided by (used in) operating activities
$

 
$
17,980

 
$
(1,320
)
 
$

 
$
16,660

Investing activities:
 
 
 
 
 
 
 
 
 
Decrease in restricted cash

 
30

 

 

 
30

Capital expenditures for property, plant and equipment

 
(9,049
)
 
(71,026
)
 

 
(80,075
)
Net cash used in investing activities

 
(9,019
)
 
(71,026
)
 

 
(80,045
)
Financing activities:
 
 
 
 
 
 
 
 
 
Proceeds from issuance of long-term debt

 

 
63,985

 

 
63,985

Repayment of long-term debt

 

 
(1,250
)
 

 
(1,250
)
Affiliate financing, net

 
(8,391
)
 
8,391

 

 

Loan origination costs

 

 
(1,462
)
 

 
(1,462
)
Distributions paid

 

 
(225
)
 

 
(225
)
Net cash provided by (used in) financing activities

 
(8,391
)
 
69,439

 

 
61,048

Net increase (decrease) in cash

 
570

 
(2,907
)
 

 
(2,337
)
Cash:
 
 
 
 
 
 
 
 
 
Beginning of period

 
1,414

 
9,640

 

 
11,054

End of period
$

 
$
1,984

 
$
6,733

 
$

 
$
8,717





F-44


19. Concentration of Credit Risk
The Partnership is a producer of sand mainly used by the oil and natural gas industry for fracturing wells. The Partnership’s business is, therefore, dependent upon economic activity within this market. For the year ended December 31, 2014, sales to three customers accounted for 64% of the Partnership’s revenue. For the year ended December 31, 2013, sales to three customers accounted for 78% of the Partnership’s revenue. Sales to four customers accounted for 100% of the Partnership's revenue from inception through December 31, 2012.
Throughout 2014, the Partnership has maintained cash balances in excess of federally insured amounts on deposit with financial institutions.

F-45


20. Subsequent Events
On January 15, 2015, we declared a cash distribution totaling $24,947, or $0.675 per common and subordinated unit. This distribution was paid on February 13, 2015 to unitholders of record on January 30, 2015. A distribution of $1,311 was declared for our holders of incentive distribution rights.


F-46