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

As of June 30, 2018,2019, the last business day of the registrant's most recently completed second fiscal quarter, the aggregate market value of common unitsstock held by non-affiliates was approximately $932,956,946$234,862,084 based on the closing price of $11.80$2.46 per common unitshare on that date.

As of February 14, 2019,2020, there were 101,062,399100,870,221 shares of common unitsstock, par value $0.01 per share, of the registrant outstanding.

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

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.

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

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

On May 31, 2019, the acquisition, allCompany completed its conversion (the "Conversion") from a Delaware limited partnership named Hi-Crush Partners LP to a Delaware corporation named Hi-Crush Inc. As a result of and at the effective date of the outstanding incentive distribution rightsConversion, each common unit representing limited partnership interests in Hi-Crush Partners LP ("common units") issued and outstanding immediately prior to the Partnership were canceled and extinguished and the sponsor waived any and all rights to receive contingent consideration payments from the Partnership or our subsidiaries pursuant to certain previously enteredConversion was automatically converted into contribution agreements to which it was a party.

Because the Conversion became effective on May 31, 2019, the current year through May 31, 2019 and prior period amounts in the engineering, design and marketing of silo-based frac sand management systems. Under the terms of the transaction, the Partnership paid cash consideration of $45.0 million and 1,279,328 newly issued common units to the sellers. The terms also include the potential for additional future consideration payments based on the achievement of established performance benchmarks through 2021. The Partnership completed this acquisition on August 1, 2018.

On August 1, 2018,May 7, 2019, the PartnershipCompany completed the acquisition of FB Industries,Proppant Logistics LLC ("Proppant Logistics"), which owns Pronghorn Logistics, LLC ("Pronghorn"), a company engaged inprovider of end-to-end proppant logistics services.

On January 18, 2019, the engineering, design and marketingCompany completed the acquisition of silo-based frac sand management systems.

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

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

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

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

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

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

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

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

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

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

Demand fundamentals are expected to improve in 20192020 compared to the latter part of 2018,2019, particularly as some of the factors limiting demand in the back half of 2018,2019, including E&P capex budget exhaustion, and pipeline take-away constraints, are alleviated.

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

The advent of In-Basinin-basin sand supply available closer to the wellsite in the Permian Basin, and to a lesser extent in the Eagle Ford, Haynesville and Mid-Con basins, has resulted in a rapid shift in supplyaway from Northern White sand supply to In-Basinin-basin sand supply. However, we believe this shift is specificsupply since 2017, specifically to finer mesh sizes of sand, particularly 100 mesh which is the principal grade produced in-basin. Northern White supplyWith the general trend towards use of 100 mesh is likely to shift to meet the demand for sand in other basins, with otherfiner mesh sizes of sand in all basins, Northern White continuingfine mesh supply is increasingly logistically challenged and coarse grade sand supply greatly exceeds demand. Over time, we believe frac sand facilities producing Northern White at a higher cost are likely to find a marketbe idled or permanently shut down due to increased competition within these regions resulting in realized sales pricing below the Permian Basin. While these shifts may cause periodic mismatches of supply and demand in particular basins,level at which such facilities can profitably operate. At this time, we do not believe thereare unable to determine which facilities will be a long-term oversupply of sand givenidled or shut down, or the projections of increasing demand.exact timeframe in which such actions might be taken.

The onset of reduced completion activity beginning in the third quarter of 2018 has caused frac sand demand growth to lag the increase in supply, and has resulted in a significant reduction in pricing, particularly for Northern White sand, that is impacting sand pricing in all basins. These factors continued to impact the market throughout 2019, particularly as E&Ps have resultedbeen more conscious of managing spending over the course of the year. This has led to a steady decline in declines inmarket pricing from the second half of 10 percent or more2018 into 2019, slowing in the latter partsecond half of 2018.2019. In response to the price decline, we and many of our competitors have reduced available capacity through the temporary idling of facilities. In September 2018, the PartnershipCompany temporarily idled dry plant operations at the Whitehall facility and resumed production in January 2019. Beginning in August 2019, the Company reduced the hours of operations at the Whitehall facility. Our Augusta facility was temporarily idled in January 2019.

Given the expectation for increased oil and natural gas exploration and production activity in North America, coupled with the increased proppant demand per well, and the increases in sand supply noted above, fracFrac sand pricing has been volatile, rising from the latter half of 2016 through the first half of 2018. During the latter half of 2018, frac sand pricing reversed trend and rapidly declined due to the combined impact of increasing supplies of In-Basinin-basin sand and reduced completions activity. Spot pricing continued to fall during 2019, as oversupply of frac sand, particularly in the Permian Basin, persisted. We believe pricing could improve during 20192020, as new supply is expectedhigher cost production facilities curtail production or opt to be absorbed by the potential increase in demand as disadvantaged supply is idled.idle or shut down operations.

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

Our current customer base includes major oil and natural gas exploration and production companies and pressure pumping service providers. For the year ended December 31, 2018,2019, sales to Chevron USA Inc. ("Chevron"), Chesapeake Operating, LLC and Anadarko Petroleum Corporation each accounted for greater than 10% of our total revenues. For the year ended December 31, 2018, sales to each of Chevron and Halliburton Company ("Halliburton") each accounted for greater than 10% of our total revenues. For the year ended December 31, 2017, sales to each of Halliburton and Liberty Oilfield Services ("Liberty") accounted for greater than 10% of our total revenues. For the year ended December 31, 2016, sales to each of Halliburton, Liberty, US Well Services, LLC and Weatherford International Ltd.Inc. accounted for greater than 10% of our total revenues.

A substantial portion of our frac sand is sold to customers with whom we have long-term contracts. For the year ended December 31, 2018,2019, we generated 87%72% of our revenues from sales of frac sand to customers with whom we had long-term contracts. We expect to continue selling a majority of our sand to our customers with long-term contracts in 20192020 and future years. As of January 1, 2019,2020, our long-term contracts have an average remaining contractual term of 2.31.7 years with remaining terms ranging from 153 to 7260 months.

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

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

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

Although the majority of the frac sand that we sell is produced from our production facilities, we can purchase, and have purchased in the past, a certain amount of frac sand and other proppant from various third parties for sale to our customers. During the years ended December 31, 2019, 2018 and 2017, the PartnershipCompany purchased 226,528, 267,628 and 142,019 tons, respectively, from third parties. During the year ended December 31, 2016, the Partnership did not purchase any sand from third parties. 

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,and Kermit facilities, may require little or no crushing during the excavation process.

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

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

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

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

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

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

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

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

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

Our PropStream last mile solution maintainslogistics and wellsite operations, named Pronghorn Energy Services, utilize silo systems and/or containers, and maintain strict proppant quality control from the mine to the blender, while also addressing environmental concerns through reduction of particulate matter emissions. We handle the full spectrum of logistics management, from railcar fleet management to truck dispatching and dedicated wellsite operation, structurally reducing costs for customers by eliminating inefficiencies throughout the proppant delivery process. PropStream providesPronghorn Energy Services provide increased transportation efficiency and reduces supply chain related congestion at the wellsite, decreasing the number of trucks required per job and decreasing or eliminating trucking demurrage costs. Our PropStream integrated logistics service isand wellsite operations are designed to meet or exceed the new federal Occupational Safety and Health Act ("OSH ActAct") respirable crystalline silica standards with respect tothat became effective in June 2018 for most aspects of hydraulic fracturing, as well as the engineering control obligations in connection with hydraulic fracturing that are set to become effective in 2021 for hydraulic fracturing. PropStream helps2021. Pronghorn Energy Services help eliminate supply risk and improve efficiency with the industry’s only fully integrated solution offering both containersilo systems and containers.

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

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

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

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

We adhere to a strict occupational health program aimed at controlling employee exposure to silica dust, which includes a silicosis prevention program comprised of routine dust sampling, medical surveillance, training and other components. Our safety program is designed to ensure compliance with MSHA and OSHA regulations. For health and safety standards, hazard and risk assessment tools and critical task specific awareness, extensive training is provided to employees. We have daily pre-task meetings and safety toolbox meetings at all our plants with personnel and conduct monthly focus fatality hazard prevention assessments as well as quarterly corporate health and safety compliance audits quarterly.audits. Additionally, we perform annual internal health and safety system audits and conduct annualrandom 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.

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

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

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

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

In addition,We are also subject to the requirements of the federal Resource Conservation and Recovery Act ("RCRA") and comparable state statutes that regulate the generation, transportation, treatment, storage, disposal and clean-up of hazardous and non-hazardous wastes. TheUnder the authority of the EPA, as well asmost states, including the WDNR in Wisconsin and the TCEQ to which the EPA has delegated portionsin Texas, administer some or all of the provisions of RCRA, programsometimes in conjunction with their own, more stringent requirements. In the course of our operations, we generate ordinary industrial wastes that may be regulated as hazardous wastes. RCRA currently exempts certain drilling fluids, produced waters and other wastes associated with exploration, development and production of crude oil and natural gas from regulation as hazardous wastes. These wastes, instead, are regulated under RCRA’s less stringent non-hazardous waste provisions, state laws or other federal laws. However, it is possible that certain oil and gas exploration and production wastes now classified as non-hazardous wastes could be classified as hazardous wastes in the future. Repeal or modification of the current RCRA exclusion or similar exemptions under state law could increase the amount of hazardous waste we are required to manage and dispose of and could cause us or our customers to incur increased operating costs, which could significantly reduce demand for local implementation, administer the RCRA program.our products and services.

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

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

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

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

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

The process for performing environmental impact studies and reviews for federal, state and local permits required for our operations involves a significant investment of time and monetary resources.capital. 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, continue or expand a project. Significant opposition and delay in the environmental review and permitting process also could impair or delay our ability to develop, continue or expand 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 business, financial condition and results of operations.

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

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

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

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

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

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

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

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

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

Raw frac sand is a proppant used in the completion and re-completion ofAs oil and natural gas wellsprices fluctuate, our customers may shift their focus back and forth between different resource plays, some of which can be located in geographic areas that do not have well-developed transportation and distribution infrastructure systems. Transportation and logistics operating expenses comprise a significant portion of our total delivered cost of sales. Therefore, serving our customers in these less-developed areas presents distribution and other operational challenges that may affect our sales and negatively impact our operating costs. Disruptions in transportation services, including shortages of railcars or trucks, or a lack of developed infrastructure, could affect our ability to stimulatetimely and maintain oilcost effectively deliver to our customers 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 shiftcould provide a competitive advantage to competitors located in demand from frac sand, including from the types of raw frac sand product that we produce and sellcloser proximity to other proppants, or the development of new processes to replace hydraulic fracturing altogether, could cause a declineour customers. Additionally, increases in the demand forprice of transportation costs, including freight charges, fuel surcharges, terminal switch fees and demurrage costs, excess railcars or trucking rates could negatively impact operating costs if we are unable to pass those increased costs along to our customers. Failure to find long-term solutions to these logistics challenges could adversely affect our ability to respond quickly to the frac sand we produce andneeds of our customers or result in a material adverse effect onadditional increased costs, and thus could negatively impact our financial condition and results of operations.

As of January 1, 2019,2020, we have contracted to sell raw frac sand under long-term supply agreements to customers with remaining terms ranging from 153 to 7260 months. For the year ended December 31, 2018,2019, we generated 87%72% of our revenues from sales of frac sand to customers with whom we had long-term contracts. A substantial portion of our logistics services are provided to customers with whom we have long-term agreements as defined in a MSA and related work orders. The MSA and related work orders are typically separate from any sand supply contract we may have with the same customer.

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

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

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

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

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

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

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

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

Our long-term Senior Notes debt is currently rated by Moody's Investors Service Inc. ("Moody's") and Standard and Poor’s ("S&P"). As of February 14, 2019,2020, the credit rating of the Partnership’sCompany’s Senior Notes was B3Caa1 from Moody’s and B-CCC+ from Standard and Poor’s.S&P. Any future downgrades in our credit ratings could negatively impact the cost of raising capital, and a downgrade could also adversely affect our ability to effectively execute aspects of our strategy and to access capital in the public markets.

We have exposure to increases in interest rates under our ABL Credit Facility. As of December 31, 2018,2019, we had no borrowings outstanding under our ABL Credit Facility. To the extent there are any outstanding borrowings under the ABL Credit Facility, changes in applicable interest rates would not affect the ABL Credit Facility’s fair market value, but could adversely affect our future results of operations and cash flows.

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

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

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

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

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

Any adverse development at our production facilities or which impact our logistics and wellsite operations, 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 or other service commitments to our customers. If we are unable to deliver contracted volumes within the required time frame or otherwise arrange for delivery from a third party, we could be required to pay make-whole payments to our customers that could have an adverse effect on our financial condition and results of operations. If we are unable to provide supply from our production facilities any reduction in the amount of frac sand available for our purchase from third partiesor unable to fulfill logistics service commitments there could havebe an adverse effect on our business, financial condition and results of operations.

John T. Boyd Company ("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:

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.

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

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

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

Although we do not directly engage in hydraulic fracturing activities, our customers purchase our frac sand for use in their hydraulic fracturing activities. IncreasedHydraulic fracturing is currently generally exempt from regulation of hydraulic fracturing may adversely impact our business, financial condition and results of operations. Theunder the federal Safe Drinking Water Act ("SDWA") regulates the underground injection of substances through the Underground Injection Control Program ("UIC") program and is typically regulated by state oil and natural gas commissions or similar agencies. However, the practice of hydraulic fracturing continues to be controversial in certain parts of the country, resulting in increased scrutiny and regulation of the fracturing process, including by federal agencies that have asserted regulatory authority or pursued investigations over certain aspects of the hydraulic fracturing process. For example, the EPA has asserted regulatory authority pursuant to the SDWA UIC Program"). Currently, with the exception of certainprogram over hydraulic fracturing activities involving the use of diesel and issued guidance covering such activities as well as published an Advanced Notice of Proposed Rulemaking regarding reporting of the chemical substances and mixtures used in hydraulic fracturing is exempt from federal regulation under the UIC Program,federal Toxic Substance Control Act. Additionally, the EPA has published an effluent limit guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and thenatural gas extraction facilities to publicly owned wastewater treatment plants. The federal Bureau of Land Management published a final rule in 2015 that established new or more stringent standards for performing hydraulic fracturing process is typically regulated by state or local governmental authorities. However,on federal and Indian lands but the practicebureau rescinded the 2015 rule in late 2017; however, litigation challenging the bureau’s decision to rescind the 2015 rule remains pending in federal district court. Also, in late 2016, the EPA released its final report on the potential impacts of hydraulic fracturing has become a contentious subject, attracting considerable public attention and continues to undergo political and regulatory scrutiny. on drinking water resources, concluding that "water cycle" activities associated with hydraulic fracturing may impact drinking water resources under some circumstances.

From time to time, Congress has considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process but no comprehensive hydraulic fracturing legislation at the federal level has been implemented to date.

In addition, to federal laws and regulations, varioussome state and local governments have implemented, oradopted, and other governmental entities are considering adopting, increased regulatory oversight of hydraulic fracturing through additional permitting requirements, operational restrictions disclosure requirements, and temporary or permanent bans on hydraulic fracturing, including states where we or our customers operate. For example, Texas, New Mexico, Oklahoma, Pennsylvania and North Dakota, among others, have adopted regulations that impose new or more stringent permitting, disclosure, disposal and well construction requirements on hydraulic fracturing operations. Also, in April 2019, the Governor of Colorado signed Senate Bill 19-181 into law, which legislation, among other things, revises the mission of the state oil and gas agency from fostering energy development in the state to instead focusing on regulating the oil and natural gas industry in a manner that is protective of public health and safety and the environment, as well as authorizing cities and counties to regulate oil and natural gas operations within their jurisdiction as they do other developments. Among other things, the Colorado oil and gas agency will consider enhanced safety and environmental protections during well development operations, including drilling and hydraulic fracturing activities. States could also elect to place certain areas such as environmentally sensitive watersheds.prohibitions on hydraulic fracturing, following the approach taken by the States of Maryland, New York and Vermont. Local governments also may seek to adopt ordinances to regulate or severely restrict the time, place and manner of hydraulic fracturing activities within their jurisdictions. Moreover, non-governmental organizations may seek to restrict hydraulic fracturing, such as wasfracturing. For example, notwithstanding the caseadoption of Colorado Senate Bill 19-181 in 2019, one or more interest groups in Colorado where certain interest groups therein have unsuccessfully pursuedalready filed new ballot initiatives in recent general election cycles that, had they been successful, would have revisedwith the state constitution or state statutes in a manner that would have made explorationJanuary 2020, in hopes of extending drilling setbacks from oil and production activities ingas development.

Increased regulation and attention given to the state more difficult or expensive in the future, including, for example, by increasing mandatory setbacks ofhydraulic fracturing process could lead to greater opposition to oil and natural gas operations from certain occupied structures and environmentally-sensitive or recreational areas.

The Augusta facility wasIn September 2018, the Company temporarily idled from October 2015 until production resumed in September 2016 anddry plant operations at the Whitehall facility was temporarily idled during the second quarter of 2016 and resumed production in March 2017. In September 2018,January 2019. Beginning in August 2019, the Partnership temporarily idled dry plantCompany reduced the hours of operations at the Whitehall facility. In January 2019, the Partnership resumed operations at the WhitehallAugusta facility and temporarily idled the Augusta facility.was idled.

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

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

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

Energy costs, primarily natural gas and electricity, represented 2% of our total sales and 10%12% of our total production costs during the year ended December 31, 2018.2019. Natural gas is the primary fuel source used for drying in the frac sand production process and, as such, our profitability is impacted by the price and availability of natural gas we purchase from third parties. Because we have not contracted for the provision of natural gas on a fixed-price basis, our costs and profitability will be impacted by fluctuations in prices for natural gas. The price and supply of natural gas are unpredictable and can fluctuate significantly based on international, political and economic circumstances, as well as other events outside our control, such as changes in supply and demand due to weather conditions, actions by OPEC and other oil and natural gas producers, regional production patterns and environmental concerns. In addition, potential climate change regulations or carbon or emissions taxes could result in higher production costs for energy, which may be passed on to us in whole or in part. The price of natural gas has been extremely volatile over the last several years. In order to manage this risk, we may hedge natural gas prices through the use of derivative financial instruments, such as forwards, swaps and futures. However, these measures carry risk (including nonperformance by counterparties) and do not in any event entirely eliminate the risk of decreased margins as a result of natural gas price increases. A significant increase in the price of energy that is not recovered through an increase in the price of our products or covered through hedging arrangements or an extended interruption in the supply of natural gas or electricity to our production facilities could have a material adverse effect on our business, financial condition, results of operations, cash flows and prospects.

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

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

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

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

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

If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and unitholdersstockholders 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.

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

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

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

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

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

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

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

An epidemic or public health crisis could disrupt our operations in several ways.  A widespread disease outbreak could reduce the demand for oil and cash availablegas, thus reducing demand for distributionfrac sand.  Additionally, a public health crisis could impede the ability of our workforce to unitholders.conduct operations.  Moreover, a health crisis could hinder our supply chain and logistics operations. 

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

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

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

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

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

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

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

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

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

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

Climate change continues to attract considerable public, politicalattention in the United States and scientific attention.in foreign countries. As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs. These efforts have included consideration by states or groupingsGHGs, as well as to limit such future emissions. As a result, the operations of statesour customers are subject to a series of cap-and-trade programs, carbon taxes, GHG reportingregulatory, political, litigation and tracking programs,financial risks associated with the production and regulations that directly limit GHG emissions from certain sources.processing of fossil fuels and emission of GHGs.

In the United States, no comprehensive climate change legislation has been implemented at the federal level, to date. However, inwith the absence of federal GHG-limiting legislation,U.S. Supreme Court finding that GHG emissions constitute a pollutant under the CAA, the EPA has determined that GHG emissions present a danger to public health and the environment and has adopted rules under authority of the federal Clean Air Act that, among other things, directly regulateestablish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of methane, a GHG emissions from oilcertain petroleum and natural gas operations. EPA’ssystem sources, implement New Source Performance Standards requiredirecting the reduction of methane from certain new, modified or reconstructed facilities in the oil and natural gas sector, to reduce these methane gas, and volatile organic compound emissions. Furthermore, EPA has established Potential for Significant Deterioration ("PSD") construction and Title V operating permit reviews fortogether with the U.S. Department of Transportation, implement GHG emissions from certain large stationary sources that emit certain principal, or "criteria," pollutants. Those sources subject to PSD permitting would be required to meet "best available control technology" standardslimits on vehicles manufactured for those GHG emissions. Internationally,operation in April 2016, the United States joinedStates. Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations or other countries in entering into aregulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, reporting and tracking programs and restriction of emissions. At the international level, there exists the United Nations-sponsored "Paris Agreement," which is a non-binding agreement negotiated in Paris, France ("Paris Agreement") for nations to limit their GHG emissions through individually-determined emission reduction goals every five years beginningafter 2020, although the United States has announced its withdrawal from such agreement, effective November 4, 2020.

Governmental, scientific and public concern over the threat of climate change arising from GHG emissions has resulted in federal political risks in the United States in the form of pledges made by certain candidates seeking the office of the President of the United States in 2020. However, in August 2017,Critical declarations made by one or more presidential candidates include proposals to ban hydraulic fracturing of oil and natural gas wells and ban new leases for production of minerals on federal properties, including onshore lands and offshore waters. Other actions to oil and natural gas production activities that could be pursued by presidential candidates may include more restrictive requirements for the U.S. State Department informedestablishment of pipeline infrastructure or the United Nationspermitting of liquefied natural gas export facilities, as well as the rescission of the United States’ intention to withdrawwithdrawal from thisthe Paris Agreement which provides for a four-year exit process beginning when it took effect in November 2016.2020. Litigation risks are also increasing, as a number of cities, local governments and other plaintiffs have sought to bring suit against the largest oil and natural gas exploration and production companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to global warming effects, such as rising sea levels, and therefore are responsible for roadway and infrastructure damages as a result, or alleging that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors by failing to adequately disclose those impacts.

The adoption and implementation of any federal or state legislation or regulations or international agreements that require reporting of GHGsimpose more stringent standards for GHG emissions from the oil and natural gas sector or otherwise restrict the areas in which this sector may produce oil and natural gas or generate GHG emissions could result in increased compliance costs or costs of GHGs from our or our customers’ equipment and operations could require us or our customers to incur increased operating costs, acquire emissions allowances or comply with new regulatory or reporting requirements, including the imposition of a carbon tax.consuming fossil fuels. Moreover, such new legislation or regulatory programs could also materially and adversely affect demand for the oil and natural gas our customers produce, which may reduce demand for our frac sand products and services. Additionally, political, financial and litigation risks may result in our oil and natural gas customers restricting or canceling production activities, incurring liability for infrastructure damages as a result of climatic changes, or impairing the ability to continue to operate in an economic manner, which also could reduce demand for our products and services. Any one or more of these developments could have a material adverse effect on our business, financial condition and results of operations. Notwithstanding potential risks related toFinally, increasing concentrations of GHG in the Earth’s atmosphere may produce climate change, the International Energy Agency estimateschanges that oilhave significant physical effects, such as increased frequency and gas will continue to represent a major shareseverity of global energy use through 2040,storms, droughts, floods, rising sea levels and other private sector studies project continued growth in demand forclimatic events. If any such climate changes were to occur, they could have an adverse effect on our financial condition and results of operations and the next two decades. However, recent activism directed at shifting funding away from companies with energy-related assets could result in limitations or restrictions on certain sourcesfinancial condition and operations of funding for the energy sector.our customers.

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

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 OxleySarbanes-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.common stock.

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

Over time, our capital and other cash needs may change significantly from our current needs, which could affect whether the board of directors declares any dividends and the amount of any dividends we may pay in the future. Our level of indebtedness may also restrict us from paying cash dividends on the common stock under certain circumstances. A decline in the market price or a nominating and corporate governance committee. Accordingly, unitholders do not have the same protections afforded to certain corporations that are subject to allliquidity, or both, of the NYSE corporate governance requirements.

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

On May 31, 2019, we make many fair market value estimates usingconverted from a methodology based onDelaware limited partnership to a Delaware corporation. From time to time, we may undertake other internal reorganizations in an effort to simplify our organizational structure, streamline our operations or for other operational reasons. Such internal reorganization may involve, among other things, the market valuecombination or dissolution of certain of our common units as a means to measure the fair market value of our assets. The IRS may challenge these valuation methodsexisting subsidiaries and the resulting allocationscreation of income, gain, lossnew subsidiaries. These transactions could be disruptive to our business, result in significant expense, require regulatory approvals, and deduction.

We lease office space for our principal executive offices in Houston, Texas and regional offices in Denver, Colorado, Odessa, Texas and Canonsburg, Pennsylvania. As of December 31, 2018,2019, we owned six production facilities located in Wisconsin and Texas, and we own all associated land. In addition, we own or operate terminal locations and lease or own railcars used to transport sand from origin to the terminal. Our PropStream last mile solution utilizes containerlogistics and wellsite operations utilize silo systems and/or silo systems,containers, and maintainsmaintain strict proppant quality control from the mine to the blender. Substantially all of our owned assets are pledged as security under our Senior Notes and ABL Credit Facility; please see Item 7, "Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources."

We completed construction of the Wyeville facility, located in Wyeville, Wisconsin, in June 2011 and expanded the facility in 2012.2012 and 2019. The Wyeville facility has an annual processing capacity of approximately 1,850,000 tons of frac sand per year. In July 2018, the Partnership announced its plans to expand the production capacity at its Wyeville facility by an additional 850,000 tons per year. Following the expansion, expected to be complete in the first quarter of 2019, the Wyeville facility’s annual processing capacity will increase to 2,700,000 tons of frac sand per year. During the year ended December 31, 2018,2019, the Wyeville facility produced and delivered 2,191,2142,472,529 tons of frac sand. As of December 31, 2018, the total cost of our plant and equipment was $63.3 million. The plant is in good physical condition and includes modern equipment powered by natural gas and electricity.

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

The total cost of our Wyeville facility was $94.9 million and the facility is in good physical condition and includes modern equipment powered by natural gas and electricity. 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.

We completed construction of the Augusta facility, located in Eau Claire County, Wisconsin, in June 2012 and expanded the facility in 2014. The Augusta facility has an annual processing capacity of approximately 2,860,000 tons of frac sand per year. The Augusta facility was temporarily idled in October 2015 until production resumed at reduced capacity levels in September 2016. The Augusta facility was again temporarily idled in January 2019. During the year ended December 31, 2018,2019, the Augusta facility produced and delivered 1,563,73356,121 tons of frac sand. As of December 31, 2018, the total cost

The Augusta facility was idled in January 2019. During 2019, we completed an impairment assessment of the Augusta facility based on current market conditions and equipment was $116.0 million. The plant is in good physical conditionthe current and includes modern equipment powered by natural gas and electricity.expected utilization of the facility. As a result, the Company recognized an impairment of $109.7 million related to the write-down of the Augusta facility, including work-in-process inventory, to its estimated fair value.

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

The total cost of our Augusta facility was $140.1 million and the facility is in good physical condition and includes modern equipment powered by natural gas and electricity. 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.

We completed construction of the Whitehall facility, located in Independence, Wisconsin and Whitehall, Wisconsin, in September 2014. The Whitehall facility has an annual processing capacity of approximately 2,860,000 tons of frac sand per year. During the year ended December 31, 2018,2019, the Whitehall facility produced and delivered 1,351,269594,128 tons of frac sand. The Whitehall facility was temporarily idled during the second quarter of 2016 and resumed production in March 2017.

In September 2018, the PartnershipCompany temporarily idled dry plant operations at the Whitehall facility and resumed production in January 2019. AsBeginning in August 2019, the Company reduced the hours of December 31, 2018,operations at the total costWhitehall facility. During 2019, we completed an impairment assessment of the Whitehall facility based on current market conditions and equipment was $112.4 million. The plant is in good physical conditionthe current and includes modern equipment powered by natural gas and electricity.expected utilization of the facility. As a result, the Company recognized an impairment of $105.7 million related to the write-down of the Whitehall facility to its estimated fair value.

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

The total cost of our Whitehall facility was $134.3 million and the facility is in good physical condition and includes modern equipment powered by natural gas and electricity. The following table summarizes certain of the key characteristics of our Whitehall facility that we believe allow us to efficiently provide our customers with high quality frac sand efficiently at competitive prices.

We completed construction of the first Kermit facility, located near Kermit, Texas, in July 2017 and the second Kermit 2 facility in December 2018. The Kermit facilities have an annual processing capacity of approximately 6,000,000 tons of frac sand per year. During the year ended December 31, 2018,2019, the Kermit facilities produced and delivered 3,044,9234,519,452 tons of frac sand. As of December 31, 2018, the cost of the Kermit facilities and equipment was $143.1 million. The plants are in good physical condition and include modern equipment powered by natural gas and electricity.

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

The total cost of our Kermit facilities was $147.5 million and the facilities are in good physical condition and includes modern equipment powered by natural gas and electricity. The following table summarizes certain of the key characteristics of our Kermit facilities that we believe allow us to efficiently provide our customers with high quality frac sand efficiently at competitive prices.

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

According to John T. Boyd has estimatedCompany ("John T. Boyd"), our proven reserves at our facilities consist of frac sand exceeding API specifications. Analysis of sand at our facilities by independent third-party testing companies indicates that they demonstrate characteristics exceeding API specifications with regard to crush strength, turbidity and roundness and sphericity. Based on third-party reserve reports by John T. Boyd, as of December 31, 2018, and2019, we intend to continue retaining third-party engineers to review our reserves onhave an annual basis.implied average reserve life of 24 years, assuming production at the current rated capacity of 17,280,000 tons of frac sand per year.

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

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

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

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

As of December 31, 2018,2019, we own or operate 1211 terminal locations as summarized in the following table:

Our terminals are strategically located to provide access to Class I railroads, which enables us to cost effectively ship product from our Wisconsin production facilities. As of December 31, 2018,2019, we leased or owned 4,9864,800 railcars used to transport sand from origin to destination and managed a fleet of approximately 596 additional railcars dedicated to our facilities by our customers or the terminal.Class I railroads.

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

As of December 31, 2018, we leased 2,624 containers used to transport sand from the terminal to the wellsite. As of December 31, 2018,2019, we owned 11 FBor leased 50 PropBeast conveyors, leased 2,978 containers from Proppant Express Investments, LLC ("PropX"), owned 15 Atlas top-filltopfill conveyors and 28owned 35 silo systems, which includesconsists of a 6-pack of silos, a conveyor for transporting sand from the silos to the blender hopper and the trailers used to transport the silos.

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

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

All of our production facilities are classified as mines and are subject to regulation by MSHA under the MSH Act. The MSHA inspects our mines on a regular basis and issues various citations and orders when it believes a violation has occurred under the MSH Act. Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.104) is included in Exhibit 95.1 to this Annual Report on Form 10-K.

OurOn May 31, 2019, the Company completed its conversion (the "Conversion") from a Delaware limited partnership named Hi-Crush Partners LP to a Delaware corporation named Hi-Crush Inc. As a result of and at the effective date of the Conversion, each common unitsunit representing limited partnerpartnership interests are listedin Hi-Crush Partners LP issued and outstanding immediately prior to the Conversion was automatically converted into one share of common stock, par value $0.01 per share, of Hi-Crush Inc. As of the open of business on and tradedJune 3, 2019, our shares of common stock commenced trading on the NYSE under the symbol "HCLP."HCR." Upon completion

As of December 31, 2018,February 14, 2020, there were 100,874,988100,870,221 shares of common unitsstock outstanding held by approximately 42,914 unitholders114 stockholders of record. Because many of our shares of common unitsstock are held by brokers and other institutions on behalf of unitholders,stockholders, we are unable to estimate the total number of unitholdersstockholders represented by these record holders.

Prior to Unitholders

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

The following performance graph provides a comparison of the cumulative total stockholder return on our common stock, the cumulative total return on the unitsRussell 3000 Index and the Standard and Poor’s Small Cap 600 GICS Oil & Gas Equipment & Services Sub-Industry Index, in any quarter.

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

On May 31, 2019, the full scopeCompany completed the Conversion from a Delaware limited partnership named Hi-Crush Partners LP to a Delaware corporation named Hi-Crush Inc. As a result of and valueat the effective date of the proppant supply chain. Conversion, each common unit representing limited partnership interests in Hi-Crush Partners LP ("common units") issued and outstanding immediately prior to the Conversion was automatically converted into one share of common stock, par value $0.01 per share, of Hi-Crush Inc. ("common stock"). As a result of the Conversion, the Company converted from an entity treated as a partnership for U.S. federal income tax purposes to an entity treated as a corporation for U.S. federal income tax purposes. As of the open of business on June 3, 2019, the common stock commenced trading on the NYSE under the ticker symbol "HCR." 

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

In June 2013, we acquired D&I Silica, LLC, ("D&I"), which transformed us into an integrated Northern White frac sand producer, transporter, marketer and distributor. To continue growth in our logistics services, onin August 1, 2018, the PartnershipCompany completed the acquisition of FB industriesIndustries Inc. ("FB Industries"), a company engaged in the engineering, design and marketing of silo-based frac sand management systems.systems, and, in January 2019, the Company acquired BulkTracer Holdings LLC, the owner of a logistics software system, PropDispatch. Additionally, in May 2019, we completed the acquisition of Proppant Logistics LLC ("Proppant Logistics"), which owns Pronghorn Logistics, LLC ("Pronghorn"), a provider of end-to-end proppant logistics services.

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

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

According to John T. Boyd Company ("John T. Boyd"), our proven reserves at our facilities consist of frac sand exceeding American Petroleum Institute ("API") specifications. Analysis of sand at our facilities by independent third-party testing companies indicates that they demonstrate characteristics exceeding API specifications with regard to crush strength, turbidity and roundness and sphericity. Based on third-party reserve reports by John T. Boyd, as of December 31, 2018,2019, we have an implied average reserve life of 2524 years, assuming production at the current rated capacity of 16,430,00017,280,000 tons of frac sand per year.

As of December 31, 2018,2019, we own or operate 1211 terminal locations throughout Pennsylvania, Ohio, Texas, Colorado and New York, of which threefive are idled and seven are capable of accommodating unit trains. Our terminals include approximately 114,000135,000 tons of rail storage capacity and approximately 140,000 tons of silo storage capacity. We seek to increase the number of terminals we operate and expand our geographic footprint, allowing us to further enhance our customer service and putting us in a stronger position to take advantage of opportunistic short-term pricing agreements.

Our terminals are strategically located to provide access to Class I railroads, which enables us to cost effectively ship product from our production facilities in Wisconsin. As of December 31, 2018,2019, we leased or owned 4,9864,800 railcars used to transport sand from origin to destination and managed a fleet of 2,169596 additional railcars dedicated to our facilities by our customers or the Class I railroads.

Our logistics and wellsite operations, named Pronghorn Energy Services, utilize silo systems and/or containers, and maintain strict proppant quality control from the Partnership entered into an agreementmine to become a memberthe blender. We handle the full spectrum of logistics management with our fully-integrated solution, from railcar fleet management, truck dispatching and dedicated wellsite operations, which structurally reduces costs for customers by eliminating inefficiencies throughout the proppant delivery process.

As of December 31, 2019, we owned or leased 50 PropBeast conveyors, leased 2,978 containers from Proppant Express Investments, LLC ("PropX"), which was established to develop critical last mile logistics equipment for the proppant industry. In October 2016, the Partnership began providing to customers its PropStream integrated logistics service, which involves loading frac sand at in-basin terminals into PropX containers before being transported by truck to the wellsite. At the wellsite, we believe the PropX proprietary conveyor system, PropBeast^®, significantly reduces noise and dust emissions due to its fully enclosed environment. As of December 31, 2018, we owned 34 PropBeast15 Atlas topfill conveyors and leased 2,624 containers from PropX.

We generate revenue by excavating, processing and delivering frac sand and providing related services. A substantial portion of our frac sand is sold to customers with whom we have long-term contracts. As of January 1, 2020, the average remaining contract term of our long-term contracts which have currentwas 1.7 years with remaining terms expiring between 2020 and 2024.ranging from 3 to 60 months. Each contract defines the minimum volume of frac sand that the customer is required to purchase, the volume that we are required to make available, the technical specifications of the product and the price per ton. During 2016, we provided contract customers with temporary market pricing arrangements at a discount to certain contracted pricing levels. In 2017, we began to revise the pricing structure in ourOur contracts for sand sourced from our Wisconsin facilities to beare periodically negotiated pricingto generally be reflective of market conditions and prices.prices within certain parameters. Our contracts for sand sourced from our Kermit facilities are generally fixed price for the life of the contract. We also sell our frac sand on the spot market at prices and other terms determined by the existing market conditions as well as the specific requirements of the customer. Delivery of sand to our customers may occur at the production facility, rail origin, terminal or wellsite.

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

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

We may,generate other revenues from time to time, sellthe sale of silo systems and related equipment to third parties at negotiated prices for the specific equipment.

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

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

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

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

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

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

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

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

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

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

We view EBITDA and Adjusted EBITDA as important indicators of performance. We define EBITDA as net income, (loss) plusplus; (i) depreciation, depletion and amortization andamortization; (ii) interest expense, net of interest income.income; and (iii) income tax expense (benefit). We define Adjusted EBITDA as EBITDA, adjusted for anyplus; (i) non-cash impairments of long-lived assetsgoodwill and goodwill,other assets; (ii) change in estimated fair value of contingent consideration; (iii) earnings (loss) from equity method investments andinvestments; (iv) gain on remeasurement of equity method investments; (v) loss on extinguishment of debt. We define distributable cash flow as Adjusted EBITDA less cash paid for interest expense, including accrualsdebt; and maintenance(vi) non-recurring business development costs and replacement capital expenditures, including accrual for reserve replacement, plus accretion of asset retirement obligations and non-cash unit-based compensation. We use distributable cash flow as a performance metric to compare cash performance of the Partnership from period to period and to compare the cash generating performance for specific periods to the cash distributions (if any) that are expected to be paid to our unitholders. Distributable cash flow will not reflect changes in working capital balances.other items. EBITDA and Adjusted EBITDA are supplemental measures utilized by our management and other users of our financial statements, such as investors, commercial banks and research analysts, and others, to assess the financial performance of our assets without regard to financing methods, capital structure or historical cost basis.

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

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

Our historical results of operations and cash flows aremay not indicative of results of operations and cash flows to be expected in the future, principallycomparable between periods for the following reasons:

Revenues generated from the sale of frac sand decreased by 32% from the third quarter of 2019 as completion activity declined primarily dueand continued pricing pressure was seen for both Northern White and in-basin sand during the fourth quarter of 2019. Average sales price was $37 per ton for the fourth quarter of 2019 compared to $43 per ton in the overall sequentialthird quarter of 2019, with the decrease being attributable to pricing pressures, greater percentage of in-basin volumes and change in final delivery points.

Other revenues are related to logistics and wellsite operations and equipment sales. The 18% decrease in sales volumes, more specificallyother revenues over the third quarter of 2019 was due primarily to decreased demand for logistics services as a result of a decline in the sales volumes of Northern White sand due to both the influx of available supply from in-basin production facilities and a slowing of well completion activity. A decline in overall average sales price was driven by both a higher percentage of volumes sold from our in-basin Kermit facility, which has a lower average price than in-basin Northern White sand sold at the terminal or wellsite, coupled with reduced pricing of Kermit sand due to the aforementioned increase in In-Basin sand supply.

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

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