Central Appalachia. For the year ended December 31, 2015,2018, we operated two mining complexes located in Central Appalachia consisting of one active underground mine and three surface mines. For the year ended December 31, 2015,2018, the mines at our Tug River and Rob Fork mining complexes produced an aggregate of approximately 0.41.2 million tons of steam coal and an estimated 0.30.5 million tons of metallurgical coal. In addition, for the year ended December 31, 2015, lessees of our Elk Horn properties produced approximately 1.7 million tons of coal.

Tug River Mining Complex. Our Tug River mining complex is located in Kentucky and West Virginia that bordersbordering the Tug River. This complex produces coal from two company operatedcompany-operated surface mines, which includes one high-wall mining unit. Coal production from these operations is delivered to the Tug Fork preparation plant for processing and then transported by truck to the Jamboree rail loadout for blending and shipping. Coal suitable for direct-ship to customers is delivered by truck directly to the Jamboree rail loadout from the mine sites. The Tug Fork plant is a modern, 350 tons per hour preparation plant utilizing heavy media circuitry that is capable of cleaning coarse and fine coal size fractions. The Jamboree loadout is located on the Norfolk Southern Railroad and is a modern unit

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train, batch weigh loadout. This mining complex produced approximately 0.21.0 million tons of steam coal and approximately 0.10.2 million tons of metallurgical coal for the year ended December 31, 2015.2018.

Rob Fork Mining Complex. Our Rob Fork mining complex is located in eastern Kentucky and produces coal from one company-operated surface mine and one company-operated underground mine. The Rob Fork mining complex is located on the CSX Railroad and consists of a modern preparation plant utilizing heavy media circuitry that is capable of cleaning coarse and fine coal size fractions and a unit train loadout with batch weighing equipment. The mining complex has significant blending capabilities allowing the blending of raw coals with washed coals to meet a wide variety of customers'customers’ needs. The Rob Fork mining complex produced approximately 0.2 million tons of steam coal and 0.20.3 million tons of metallurgical coal for the year ended December 31, 2015.2018.

        Deane Mining Complex.    Our Deane mining complex was located in eastern Kentucky and included one underground steam coal mine that was idle during the year ended December 31, 2015. The infrastructure consisted of a preparation plant utilizing heavy media circuitry capable of cleaning coarse and fine coal size fractions, as well as a unit train loadout facility with batch weighing equipment capable of loading in excess of 10,000 tons into railcars in approximately four hours. The Deane complex was sold to a third party in December 2015 (see Note 6 of the consolidated financial statements included elsewhere in this annual report for further information). Please read ""—Recent Developments—Dean Mining Complex Sale."

        Rhino Eastern Mining Complex.Northern Appalachia.    The Rhino Eastern mining complex was previously owned through a joint venture where we had a 51% membership interest in, and served as manager for the mining complex located in Raleigh and Wyoming Counties, West Virginia. The joint venture was dissolved in January 2015 and an affiliate of Patriot, our previous joint venture partner, assumed ownership and operation of the mining operations.

        Elk Horn Coal Leasing.    The Elk Horn Coal Company ("Elk Horn") is primarily a coal leasing company located in eastern Kentucky that provides us with coal royalty revenues. For the year ended December 31, 2015, Elk Horn lessees produced approximately 1.7 million tons of coal from our Elk Horn properties.

        Northern Appalachia.    We operate two2018, we operated one mining complexescomplex located in Northern Appalachia consisting of one company-operated underground mine and two company-operated surface mines.mine. For the year ended December 31, 2015, these mines2018, the mine produced an aggregate of approximately 0.90.4 million tons of steam coal. We sold our Sands Hill Mining operation in November 2017, which consisted of one company-operated surface mine.

Hopedale Mining Complex. The Hopedale mining complex includes an underground mine located in Hopedale, Ohio approximately five miles northeast of Cadiz, Ohio. Coal produced from the Hopedale mine is first cleaned at our Nelms preparation plant located on the Ohio Central Railroad and the Wheeling & Lake Erie Railroad and then shipped by train or truck to our customers. The infrastructure includes a full-service loadout facility. This underground mining operation produced approximately 0.70.4 million tons of steam coal for the year ended December 31, 2015.2018.

        Sands Hill Mining Complex.    We currently operate two surface mines at our Sands Hill mining complex, located near Hamden, Ohio. The infrastructure includes a preparation plant along with a river front barge and dock facility on the Ohio River. The Sands Hill mining complex produced approximately 0.2 million tons of steam coal and approximately 0.4 million tons of limestone aggregate for the year ended December 31, 2015.

Western Bituminous Region. We operate one mining complex in the Western Bituminous region that produces coal from an underground mine located in Emery and Carbon Counties, Utah. We also had one underground mine located in the Western Bituminous region in Colorado (McClane Canyon)

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that was permanently idled at the end of 2013 (see Note 6 of the consolidated financial statements included elsewhere in this annual report for further information).2013.

Castle Valley Mining Complex. Our Castle Valley mining complex includes one underground mine located in Emery and Carbon Counties, Utah and include coal reserves and non-reserve coal deposits, underground mining equipment and infrastructure, an overland belt conveyor system, a loading facility and support facilities. We produced approximately 1.0 million tons of steam coal from one underground mine at this complex for the year ended December 31, 2015.2018.

Illinois Basin.    In May 2012, we completedWe operate one mining complex in the purchase of certain rights toIllinois Basin region that produces coal leases and surface property that is contiguous to the Green River andfrom an underground mine located in Daviess and McLean counties in western Kentucky where we constructed a new underground mining complex. The coal leases and property are contiguous to the Green River. The property is fully permittedWe also have an estimated 111.1 million of proven and provides us with access toprobable reserves in the Taylorville Field area in the Illinois Basin coal that is adjacent to a navigable waterway, which could allow for exports to non-U.S. customers. During 2014, we completed the initial construction of a new underground mining operation on this property. Production began in late May 2014 and the first barge shipments of coal departed from this facility in early July 2014. We have long-term sales contracts with local electric utility customers and we have other potential customers that we believe could lead to additional long-term sales agreements if we can successfully expand our production capacity at this operation.remain undeveloped.

Pennyrile Mining Complex. In mid-2014, we completed the initial construction of a new underground mining operation on the purchased property, referred to as our Pennyrile mining complex, which includes one underground mine, a preparation plant and river loadout facility. ProductionThe property is adjacent to a navigable waterway, which allows for exports to non-U.S. customers. We produced approximately 1.3 million tons of steam coal from this new underground mine began in mid-2014 and we produced approximately 0.8 million tons for the year ended December 31, 2015.2018. We believe the possibility exists to expand production up to 2.0 million tons per year with further development of the mine at the Pennyrile complex.

Other Non-Mining Operations

In addition to our mining operations, we operate severalvarious subsidiaries which provide auxiliary services for our coal mining operations. Rhino Trucking provides our southeastern Ohio coal operations with reliable transportation to our customers where rail is not available. Rhino Services is responsible for mine-related construction, site and roadway maintenance and post-mining reclamation. Through Rhino Services, we plan and monitor each phase of our mining projects as well as the post-mining reclamation efforts. We also perform the majority of our drilling and blasting activities at our company-operated surface mines in-house rather than contracting to a third party.

Other Natural Resource Assets

Oil and Natural Gas

In addition to our coal operations, we have invested in oil and natural gas assets and operations thatoperations.

In December 2012, we believe helpmade an initial investment in a new joint venture, Muskie Proppant LLC (“Muskie”), with affiliates of Wexford Capital. In November 2014, we contributed our investment interest in Muskie to diversify our income stream.

        In 2011, we began to investMammoth Energy Partners LP (“Mammoth”) in oil and natural gas mineral rights and operations in the Utica Shale region of eastern Ohio. As of December 31, 2013, we had invested a total of approximately $31.1 millionreturn for a 5% netlimited partner interest in a portfolioMammoth. In October 2016, we contributed our limited partner interests in Mammoth to Mammoth, Inc. in exchange for 234,300 shares of oil and natural gas leases in the Utica Shale region along with approximately $23.3 million in drilling costs, which represented our proportionate ownership share in the portfolio. Gulfport, the operatorcommon stock of the portfolio, began drilling and testing wells in the region in 2012 and we received our proportionate share (5%) of revenue from the hydrocarbons produced and sold by the operator on our acreage, which totaled approximately $5.6 million for the year ended December 31, 2013. In March 2014, we completed a purchase and sale agreement to sell our entire Utica Shale joint interest investment to Gulfport for approximately $184.0 million, which provided us a substantial return on our initial investment.

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 During 2011, we completed the acquisition of certain oil and natural gas mineral rights in the Cana Woodford region of western Oklahoma for a total purchase price of approximately $8.1 million. We began to receive royalty revenues from these mineral rights in early 2012 and received approximately $149,000 and $149,000 in royalty revenue during 2015 and 2014, respectively. In August 2015, we completed the sale of our Cana Woodford mineral rights for approximately $5.7 million.

In September 2014, we made an initial investment of $5.0 million in a new joint venture, Sturgeon Acquisitions LLC ("Sturgeon"(“Sturgeon”), with affiliates of Wexford Capital and Gulfport. Sturgeon subsequently acquired 100% of the outstanding equity interests of certain limited liability companies located in Wisconsin that provide frac sand for oil and natural gas drillers in the United States.Gulfport Energy Corporation (NASDAQ: GPOR) (“Gulfport”). We accountaccounted for the investment in this joint venture and results of operations under the equity method. We recordedmethod based upon our proportionate portion of the operating gains for this investment during 2015 and 2014 of approximately $0.3 million and $0.4 million, respectively.

        In December 2012, we made an initial investment of approximately $2.0 million in a new joint venture, Muskie Proppant LLC ("Muskie"), with affiliates of Wexford Capital. Muskie was formed to provide sand for fracking operations to drillers in the Utica Shale region and other oil and natural gas basins in the U.S.ownership percentage. We recorded our proportionate share of the operating lossincome for 2014 approximately $0.1 million. Duringthis investment for the year ended December 31, 2014, we contributed additional capital based upon our ownership interest to the Muskie joint venture in the amount2017 of $0.2 million.approximately $36,000. In addition, during the year ended December 31, 2013, we provided a loan based upon our ownership share to Muskie in the amount of $0.2 million, which was fully repaid in November 2014 in conjunction with our contribution of our interest in Muskie to Mammoth Energy Partners LP ("Mammoth"). In November 2014,June 2017, we contributed our investment interestlimited partner interests in MuskieSturgeon to Mammoth Inc. in returnexchange for 336,447 shares of common stock of Mammoth Inc. As of December 31, 2018, we owned 104,100 shares of Mammoth Inc.

As of December 31, 2018 and 2017, we recorded our investment in Mammoth Inc. as a limited partner interestcurrent asset, which was classified as available-for-sale. We have included our investment in Mammoth. Mammoth was formed to own various companies that provide services to companies who engageInc. in the exploration and development of North American onshore unconventional oil and natural gas reserves. Mammoth's companies provide services that include completion and production services, contract land and directional drilling services and remote accommodation services.Other category for segment reporting purposes.

 In addition, during the second quarter of 2012 we formed a services company ("Razorback") to provide drill pad construction services in the Utica Shale for drilling operators. Razorback has completed the construction of numerous drill pads since its inception, along with the construction of impoundments for fracking water and the construction of several access roads for operators in the Utica Shale region. We ceased operations of Razorback during 2015 due to decreased drilling activity in the Utica Shale region.

Limestone

        Incidental to our coal mining process, we mine limestone from reserves located at our Sands Hill mining complex and sell it as aggregate to various construction companies and road builders that are located in close proximity to the mining complex when market conditions are favorable. We believe that our production of limestone provides us with an additional source of revenues at low incremental capital cost.

Coal Customers

General

Our primary customers for our steam coal are electric utilities and industrial consumers, and the metallurgical coal we produce is sold primarily to domestic and international steel producers.producers and coal brokers. For the year ended December 31, 2015,2018, approximately 95%81.0% of our coal sales tons consisted of steam coal and approximately 5%19.0% consisted of metallurgical coal. For the year ended December 31, 2015,2018, approximately 84%40.0% of our coal sales tons that we produced were sold to electric utilities. The majority of our electric utility customers purchase coal for terms of one to three years, but we also supply coal

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on a spot basis for some of our customers. For the year ended December 31, 2015,2018, we derived approximately 83.9%80.0% of our total coal revenues from sales to our ten largest customers, with affiliates of our top three customers accounting for approximately 45.2%40.4% of our coal revenues for that period: PPL Corporation (19.7%); NRG Energy, Inc. (fka GenOn Energy, Inc.) (12.9%); and PacifiCorp Energy (12.6%). Incidental to our coal mining process, we mine limestone and sell it as aggregate to various construction companies and road builders that are located in close proximity to our Sands Hill mining complex.period.

Coal Supply Contracts

For each of the years ended December 31, 20152018 and 2014,2017, approximately 84%64% and 78%59%, respectively, of our aggregate coal tons sold were sold through supply contracts. We expect to continue selling a significant portion of our coal under supply contracts. As of December 31, 2015,2018, we had commitments under supply contracts to deliver annually scheduled base quantities as follows:

Some of the contracts have sales price adjustment provisions, subject to certain limitations and adjustments, based on a variety of factors and indices.

Quality and volumes for the coal are stipulated in coal supply contracts, and in some instances buyers have the option to vary annual or monthly volumes. Most of our coal supply contracts contain provisions requiring us to deliver coal within certain ranges for specific coal characteristics such as heat content, sulfur, ash, hardness and ash fusion temperature. Failure to meet these specifications can result in economic penalties, suspension or cancellation of shipments or termination of the contracts. Some of our contracts specify approved locations from which coal may be sourced. Some of our contracts set out mechanisms for temporary reductions or delays in coal volumes in the event of a force majeure, including events such as strikes, adverse mining conditions, mine closures, or serious transportation problems that affect us or unanticipated plant outages that may affect the buyers.

The terms of our coal supply contracts result from competitive bidding procedures and extensive negotiations with customers. As a result, the terms of these contracts, including price adjustment features, price re-opener terms, coal quality requirements, quantity parameters, permitted sources of supply, future regulatory changes, extension options, force majeure, termination and assignment provisions, vary significantly by customer.

Coal Lease Agreements

        With respect to our coal leasing operations, we enter into leases with coal mine operators granting them the right to mine and sell coal from our Elk Horn properties in exchange for a royalty payment. Generally the lease terms provide us with a royalty fee of 6% to 9% of the gross sales price of the coal, with a minimum royalty fee ranging from $1.85 to $4.75 per ton. The terms of such leases vary from five years to the life of the reserves. A minimum royalty is required annually or monthly whether or not the property is mined.

Transportation

We ship coal to our customers by rail, truck or barge. For the year ended December 31, 2015, the majority of our coal sales tonnage was shipped by rail. The majorityA significant portion of our coal is transported to customers by either the CSX Railroad or the Norfolk Southern Railroad in eastern Kentucky and by

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the Ohio Central Railroad or the Wheeling & Lake Erie Railroad in Ohio. In addition, in southeastern Ohio, we use our own trucking operations to transport coal to our customers where rail is not available. We use third-party trucking to transport coal to our customers in Utah. For our Pennyrile complex in western Kentucky, coal is transported to our customers via barge from our river loadout on the Green River located on our Pennyrile mining complex. In addition, coal from certain of our Central Appalachia and southern Ohio mines is located within economical trucking distance to the Big Sandy River and/or the Ohio River and can be transported by barge. It is customary for customers to pay the transportation costs to their location.

We believe that we have good relationships with rail carriers, barge companies and truck companies due, in part, to our modern coal-loading facilities at our loadouts and the working relationships and experience of our transportation and distribution employees.

Suppliers

Principal supplies used in our business include diesel fuel, explosives, maintenance and repair parts and services, roof control and support items, tires, conveyance structures, ventilation supplies and lubricants. We use third-party suppliers for a significant portion of our equipment rebuilds and repairs drilling services and construction.

We have a centralized sourcing group for major supplier contract negotiation and administration, for the negotiation and purchase of major capital goods and to support the mining and coal preparation plants. We are not dependent on any one supplier in any region. We promote competition between suppliers and seek to develop relationships with those suppliers whose focus is on lowering our costs. We seek suppliers who identify and concentrate on implementing continuous improvement opportunities within their area of expertise.

Competition

The coal industry is highly competitive. There are numerous large and small producers in all coal producing regions of the United States and we compete with many of these producers. Our main competitors include Alliance Resource Partners LP, Alpha Natural Resources, Inc., Arch Coal, Inc., Booth Energy Group, CONSOL Energy Inc.,Blackhawk Mining, LLC, Murray Energy Corporation, Foresight Energy LP, Westmoreland Resource Partners, LP, and Bowie Resource PartnersWolverine Fuels, LLC.

The most important factors on which we compete are coal price, coal quality and characteristics, transportation costs and the reliability of supply. Demand for coal and the prices that we will be able to obtain for our coal are closely linked to coal consumption patterns of the domestic electric generation industry and international consumers. These coal consumption patterns are influenced by factors beyond our control, including demand for electricity, which is significantly dependent upon economic activity and summer and winter temperatures in the United States, government regulation, technological developments and the location, availability, quality and price of competing sources of fuel such as natural gas, oil and nuclear, and alternative energy sources such as hydroelectric power, solar power and wind power.

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Regulation and Laws

Our operations are subject to regulation by federal, state and local authorities on matters such as:

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employee health and safety;



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governmental approvals and other authorizations such as mine permits, as well as other licensing requirements;



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air quality standards;



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water quality standards;



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storage, treatment, use and disposal of petroleum products and other hazardous substances;



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plant and wildlife protection;



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reclamation and restoration of mining properties after mining is completed;



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the discharge of materials into the environment, including waterways or wetlands;



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storage and handling of explosives;



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wetlands protection;



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surface subsidence from underground mining;



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the effects, if any, that mining has on groundwater quality and availability; and



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legislatively mandated benefits for current and retired coal miners.

In addition, many of our customers are subject to extensive regulation regarding the environmental impacts associated with the combustion or other use of coal, which could affect demand for our coal. The possibility exists that new laws or regulations, or new interpretations of existing laws or regulations, may be adopted that may have a significant impact on our mining operations oil and natural gas investments, or our customers'customers’ ability to use coal. Moreover, environmental citizen groups frequently challenge coal mining, terminal construction, and other related projects.

We are committed to conducting mining operations in compliance with applicable federal, state and local laws and regulations. However, because of extensive and comprehensive regulatory requirements, violations during mining operations occur from time to time. Violations, including violations of any permit or approval, can result in substantial civil and in severe cases, criminal fines and penalties, including revocation or suspension of mining permits. None of the violations to date have had a material impact on our operations or financial condition.

While it is not possible to quantify the costs of compliance with applicable federal and state laws and regulations, those costs have been and are expected to continue to be significant. Nonetheless, capital expenditures for environmental matters have not been material in recent years. We have accrued for the present value of estimated cost of reclamation and mine closings, including the cost of treating mine water discharge when necessary. The accruals for reclamation and mine closing costs are based upon permit requirements and the costs and timing of reclamation and mine closing procedures. Although management believes it has made adequate provisions for all expected reclamation and other costs associated with mine closures, future operating results would be adversely affected if we later determined these accruals to be insufficient. Compliance with these laws and regulations has substantially increased the cost of coal mining for all domestic coal producers. Most of the statutes discussed below apply to exploration and development activities associated with our oil and natural gas investments as well, and therefore we do not present a separate discussion of statutes related to those activities.

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Mining Permits and Approvals

Numerous governmental permits or approvals are required for coal mining operations. When we apply for these permits and approvals, we are often required to assess the effect or impact that any proposed production of coal may have upon the environment. The permit application requirements may be costly and time consuming, and may delay or prevent commencement or continuation of mining operations in certain locations. In addition, these permits and approvals can result in the imposition of numerous restrictions on the time, place and manner in which coal mining operations are conducted. Future laws and regulations may emphasize more heavily the protection of the environment and, as a consequence, our activities may be more closely regulated. Laws and regulations, as well as future interpretations or enforcement of existing laws and regulations, may require substantial increases in equipment and operating costs, or delays, interruptions or terminations of operations, the extent of any of which cannot be predicted. For example, in January 2016, the federal Bureau of Land Management announced a moratorium on new coal leases for federal lands. The moratorium does not affect existing leases. In addition, the permitting process for certain mining operations can extend over several years, and can be subject to judicial challenge, including by the public. Some required mining permits are becoming increasingly difficult to obtain in a timely manner, or at all. We may experience difficulty and/or delay in obtaining mining permits in the future.

Regulations provide that a mining permit can be refused or revoked if the permit applicant or permittee owns or controls, directly or indirectly through other entities, mining operations which have outstanding environmental violations. Although, like other coal companies, we have been cited for violations in the ordinary course of business, we have never had a permit suspended or revoked because of any violation, and the penalties assessed for these violations have not been material.

Before commencing mining on a particular property, we must obtain mining permits and approvals by state regulatory authorities of a reclamation plan for restoring, upon the completion of mining, the mined property to its approximate prior condition, productive use or other permitted condition.

Mine Health and Safety Laws

Stringent safety and health standards have been in effect since the adoption of the Coal Mine Health and Safety Act of 1969. The Federal Mine Safety and Health Act of 1977 (the "Mine Act"“Mine Act”), and regulations adopted pursuant thereto, significantly expanded the enforcement of health and safety standards and imposed comprehensive safety and health standards on numerous aspects of mining operations, including training of mine personnel, mining procedures, blasting, the equipment used in mining operations and other matters. The Mine Safety and Health Administration ("MSHA"(“MSHA”) monitors compliance with these laws and regulations. In addition, the states where we operate also have state programs for mine safety and health regulation and enforcement. Federal and state safety and health regulations affecting the coal industry are complex, rigorous and comprehensive, and have a significant effect on our operating costs.

The Mine Act is a strict liability statute that requires mandatory inspections of surface and underground coal mines and requires the issuance of enforcement action when it is believed that a standard has been violated. A penalty is required to be imposed for each cited violation. Negligence and gravity assessments result in a cumulative enforcement scheme that may result in the issuance of an order requiring the immediate withdrawal of miners from the mine or shutting down a mine or any section of a mine or any piece of mine equipment. The Mine Act contains criminal liability provisions. For example, criminal liability may be imposed for corporate operators who knowingly or willfully authorize, order or carry out violations. The Mine Act also provides that civil and criminal penalties may be assessed against individual agents, officers and directors who knowingly authorize, order or carry out violations.

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We have developed a health and safety management system that, among other things, includes training regarding worker health and safety requirements including those arising under federal and state laws that apply to our mines. In addition, our health and safety management system tracks the performance of each operational facility in meeting the requirements of safety laws and company safety policies. As an example of the resources we allocate to health and safety matters, our safety management system includes a company-wide safety director and local safety directors who oversee safety and compliance at operations on a day-to-day basis. We continually monitor the performance of our safety management system and from time-to-time modify that system to address findings or reflect new requirements or for other reasons. We have even integrated safety matters into our compensation and retention decisions. For instance, our bonus program includes a meaningful evaluation of each eligible employee'semployee’s role in complying with, fostering and furthering our safety policies.

We evaluate a variety of safety-related metrics to assess the adequacy and performance of our safety management system. For example, we monitor and track performance in areas such as "accidents,“accidents, reportable accidents, lost time accidents and the lost-time accident frequency rate"rate” and a number of others. Each of these metrics provides insights and perspectives into various aspects of our safety systems and performance at particular locations or mines generally and, among other things, can indicate where improvements are needed or further evaluation is warranted with regard to the system or its implementation. An important part of this evaluation is to assess our performance relative to certain national benchmarks.

For the year ended December 31, 20152018 our average MSHA violations per inspection day was 0.360.39 as compared to the most recent national average of 0.770.59 violations per inspection day for coal mining activity as reported by MSHA, or 53.25%33.89% below this national average.

Mining accidents in the last several years in West Virginia, Kentucky and Utah have received national attention and instigated responses at the state and national levels that have resulted in increased scrutiny of current safety practices and procedures at all mining operations, particularly underground mining operations. For example, in 2014, MSHA adopted a final rule that reducesto lower miners’ exposure to respirable coal mine dust. The rule had a phased implementation schedule. The second phase of the permissible concentrationrule went into effect in February 2016, and requires increased sampling frequency and the use of continuous personal dust monitors. In August 2016, the third and final phase of the rule became effective, reducing the overall respirable dust standard in underground coal mines from the current standard of 2.0 to 1.5 milligrams per cubic meter of air to 1.5 milligram per cubic meter. The rule has a phased implementation schedule, the final phase required to be implemented by August 2016. Under the phased approach, operators will be required to adopt new measures and procedures for dust sampling, record keeping, and medical surveillance. More recently,air. Additionally, in September 2015, MSHA issued a proposed rule requiring the installation of proximity detection systems on underground coal hauling systems used on the mining section.machines and scoops. Proximity detection is a technology that uses electronic sensors to detect motion and the distance between a miner and a machine. These systems provide audible and visual warnings, and automatically stop moving machines when miners are in the machines'machines’ path. These and other new safety rules could result in increased compliance costs on our operations.

In addition, more stringent mine safety laws and regulations promulgated by thesethe states and the federal government have included increased sanctions for non-compliance. For example, in 2006, the Mine Improvement and New Emergency Response Act of 2006, or MINER Act, was enacted. The MINER Act significantly amended the Mine Act, requiring improvements in mine safety practices, increasing criminal penalties and establishing a maximum civil penalty for non-compliance, and expanding the scope of federal oversight, inspection and enforcement activities. Since passage of the MINER Act in 2006, enforcement scrutiny has increased, including more inspection hours at mine sites, increased numbers of inspections and increased issuance of the number and the severity of enforcement actions and related penalties. For example, in July 2014, MSHA proposed a rule that revises its civil penalty assessment provisions and how regulators should approach calculating penalties, which, in some instances, could resultedresult in increased civil penalty assessments for medium and larger mine operators and contractors by 300 to 1,000 percent. MSHA proposed some revisions to the original proposed rule in February 2015, but, to date, has not taken any further action. Other states have proposed or passed similar bills, resolutions or

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regulations addressing enhanced mine safety practices and increased fines and penalties. Moreover, workplace accidents, such as the April 5, 2010, Upper Big Branch Mine incident, have resulted in more inspection hours at mine sites, increased number of inspections and increased issuance of the number and severity of enforcement actions and the passage of new laws and regulations. These trends are likely to continue.

 Indeed, in

In 2013, MSHA began implementing its recently released Pattern of Violation ("POV"(“POV”) regulations under the Mine Act. Under this regulation, MSHA eliminated the ninety (90) day window to take corrective action and engage in mitigation efforts for mine operators who met certain initial POV screening criteria. Additionally, MSHA will make POV determinations based upon enforcement actions as issued, rather than enforcement actions that have been rendered final following the opportunity for administrative or judicial review. After a mine operator has been placed on POV status, MSHA will thereafter issue an order withdrawing miners from the area affected by any enforcement action designated by MSHA as posing a significant and substantial, or S&S, hazard to the health and/or safety of miners. Further, once designated as a POV mine, a mine operator can be removed from POV status only upon: (1) a complete inspection of the entire mine with no S&S enforcement actions issued by MSHA; or (2) no POV-related withdrawal orders being issued by MSHA within ninety (90) days of the mine operator being placed on POV status. Although it remains to be seen how these new regulations will ultimately affect production at our mines, they are consistent with the trend of more stringent enforcement.

From time to time, certain portions of individual mines have been required to suspend or shut down operations temporarily in order to address a compliance requirement or because of an accident. For instance, MSHA issues orders pursuant to Section 103(k) that, among other things, call for operations in the area of the mine at issue to suspend operations until compliance is restored. Likewise, if an accident occurs within a mine, the MSHA requirements call for all operations in that area to be suspended until the circumstance leading to the accident has been resolved. During the fiscal year ended December 31, 20142018 (as in earlier years), we received such orders from government agencies and have experienced accidents within our mines requiring the suspension or shutdown of operations in those particular areas until the circumstances leading to the accident have been resolved. While the violations or other circumstances that caused such an accident were being addressed, other areas of the mine could and did remain operational. These circumstances did not require us to suspend operations on a mine-wide level or otherwise entail material financial or operational consequences for us. Any suspension of operations at any one of our locations that may occur in the future may have material financial or operational consequences for us.

It is our practice to contest notices of violations in cases in which we believe we have a good faith defense to the alleged violation or the proposed penalty and/or other legitimate grounds to challenge the alleged violation or the proposed penalty. We exercise substantial efforts toward achieving compliance at our mines. For example, we have further increased our focus with regard to health and safety at all of our mines. These efforts include hiring additional skilled personnel, providing training programs, hosting quarterly safety meetings with MSHA personnel and making capital expenditures in consultation with MSHA aimed at increasing mine safety. We believe that these efforts have contributed, and continue to contribute, positively to safety and compliance at our mines. In "Part“Part 1, Item 4. Mine Safety Disclosure"Disclosure” and in Exhibit 9595.1 to this Annual Report on Form 10-K, we provide additional details on how we monitor safety performance and MSHA compliance, as well as provide the mine safety disclosures required pursuant to Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act.

Black Lung Laws

Under the Black Lung Benefits Act of 1977 and the Black Lung Benefits Reform Act of 1977, as amended in 1981, coal mine operators must make payments of black lung benefits to current and

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former coal miners with black lung disease, some survivors of a miner who dies from this disease, and to fund a trust fund for the payment of benefits and medical expenses to claimants who last worked in the industry prior to January 1, 1970. To help fund these benefits, a tax is levied on production of $1.10$0.50 per ton for underground-mined coal and $0.55$0.25 per ton for surface-mined coal, but not to exceed 4.4%2.0% of the applicable sales price.price (rates effective January 1, 2019). This excise tax does not apply to coal that is exported outside of the United States. In 2015,2018, we recorded approximately $3.2$2.5 million of expense related to this excise tax.

The Patient Protection and Affordable Care Act includes significant changes to the federal black lung program including an automatic survivor benefit paid upon the death of a miner with an awarded black lung claim and establishes a rebuttable presumption with regard to pneumoconiosis among miners with 15 or more years of coal mine employment that are totally disabled by a respiratory condition. These changes could have a material impact on our costs expended in association with the federal black lung program. We may also be liable under state laws for black lung claims that are covered through either insurance policies or state programs.

Workers'Workers’ Compensation

We are required to compensate employees for work-related injuries under various state workers'workers’ compensation laws. The states in which we operate consider changes in workers'workers’ compensation laws from time to time. Our costs will vary based on the number of accidents that occur at our mines and other facilities, and our costs of addressing these claims. We are insured under the Ohio State Workers Compensation Program for our operations in Ohio. Our remaining operations, including Central Appalachia, the Illinois Basin and the Western Bituminous region, are insured through Rockwood Casualty Insurance Company.

Surface Mining Control and Reclamation Act ("SMCRA"(“SMCRA”)

SMCRA establishes operational, reclamation and closure standards for all aspects of surface mining, including the surface effects of underground coal mining. SMCRA requires that comprehensive environmental protection and reclamation standards be met during the course of and upon completion of mining activities. In conjunction with mining the property, we reclaim and restore the mined areas by grading, shaping and preparing the soil for seeding. Upon completion of mining, reclamation generally is completed by seeding with grasses or planting trees for a variety of uses, as specified in the approved reclamation plan. We believe we are in compliance in all material respects with applicable regulations relating to reclamation.

SMCRA and similar state statutes require, among other things, that mined property be restored in accordance with specified standards and approved reclamation plans. The act requires that we restore the surface to approximate the original contours as soon as practicable upon the completion of surface mining operations. The mine operator must submit a bond or otherwise secure the performance of these reclamation obligations. Mine operators can also be responsible for replacing certain water supplies damaged by mining operations and repairing or compensating for damage to certain structures occurring on the surface as a result of mine subsidence, a consequence of long-wall mining and possibly other mining operations. In addition, the Abandoned Mine Lands Program, which is part of SMCRA, imposes a tax on all current mining operations, the proceeds of which are used to restore mines closed prior to SMCRA'sSMCRA’s adoption in 1977. The maximum tax for the period from October 1, 2012 through September 30, 2021, has been decreased to 28 cents per ton on surface mined coal and 12 cents per ton on underground mined coal. However, this fee is subject to change. The President's Budget for Fiscal Year 2017 proposes to restore fees on coal production to pre-2006 levelsShould this fee be increased in order to fund the reclamation of abandoned mines. If enacted into law, this proposal would increase the fees on surface mining to $0.35 per ton and increase the fees on underground mining to $0.15 per ton. Givenfuture, given the market for coal, it is unlikely that coal mining companies would be able to recover all of these fees from their customers. As of December 31, 2015,2018, we had accrued approximately $23.7$18.5 million for the

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estimated costs of reclamation and mine closing, including the cost of treating mine water discharge when necessary. In addition, states from time to time have increased and may continue to increase their fees and taxes to fund reclamation of orphaned mine sites and abandoned mine drainage control on a statewide basis.

After a mine application is submitted, public notice or advertisement of the proposed permit action is required, which is followed by a public comment period. It is not uncommon for a SMCRA mine permit application to take over two years to prepare and review, depending on the size and complexity of the mine, and another two years or even longer for the permit to be issued. The variability in time frame required to prepare the application and issue the permit can be attributed primarily to the various regulatory authorities'authorities’ discretion in the handling of comments and objections relating to the project received from the general public and other agencies. Also, it is not uncommon for a permit to be delayed as a result of judicial challenges related to the specific permit or another related company'scompany’s permit.

Federal laws and regulations also provide that a mining permit or modification can be delayed, refused or revoked if owners of specific percentages of ownership interests or controllers (i.e., officers and directors or other entities) of the applicant have, or are affiliated with another entity that has outstanding violations of SMCRA or state or tribal programs authorized by SMCRA. This condition is often referred to as being "permit blocked"“permit blocked” under the federal Applicant Violator Systems, or AVS. Thus, non-compliance with SMCRA can provide the basesbasis to deny the issuance of new mining permits or modifications of existing mining permits, although we know of no basis by which we would be (and we are not now) permit-blocked.

In addition, a February 2014 decision by the U.S. District Court for the District of Columbia invalidated the Office of Surface Mining Reclamation and Enforcement's ("OSM"Enforcement’s (“OSM”) 2008 Stream Buffer Zone Rule, which prohibited mining disturbances within 100 feet of streams, subject to various exemptions. In July 2015,December 2016, the OSM proposedpublished the final Stream Protection Rule, which, among other things, would requirehave required operators to test and monitor conditions of streams they might impact before, during and after mining. It also strengthens requirements forThe final rule took effect in January 2017 and would have required mine operators to collect pre-miningadditional baseline data about the site of athe proposed mining operation and adjacent areas; imposed additional surface and groundwater monitoring requirements; enacted specific requirements for the protection or restoration of perennial and intermittent streams; and imposed additional bonding and financial assurance requirements. However, in February 2017, the rule was revoked pursuant to establish an adequate baseline for evaluation. Thethe Congressional Review Act. Accordingly, the rule would also require operators to restore streams“shall have no force or effect” and return mined areas toOSM cannot promulgate a condition capable of supporting the land uses available before mining activities occurred. We could face significant operating restrictions, as well as increased monitoring and restoration costs, as a result of OSM's proposed rule.

        We are unable to predict the impact, if any, of these actions by the OSM, although the actions potentially could result in additional delays and costs associated with obtaining permits, prohibitions or restrictions relating to mining activities near streams, and additional enforcement actions. In addition,substantially similar rule absent future legislation. Whether Congress has proposed, and may in thewill enact future propose, legislation to restrict the placement of mining material in streams. The requirements of therequire a new Stream Protection Rule remains uncertain. A new Stream Protection Rule, or future legislation, when adopted, will likely be stricter than the prior Stream Buffer Zone Rule to further protect streams from the impact of surface mining,other new SMCRA regulations, could result in additional material costs, obligations, and may adversely affectrestrictions associated with our business and operations.

Surety Bonds

Federal and state laws require a mine operator to secure the performance of its reclamation obligations required under SMCRA through the use of surety bonds or other approved forms of performance security to cover the costs the state would incur if the mine operator were unable to fulfill its obligations. It has become increasingly difficult for mining companies to secure new surety bonds without the posting of partial collateral. In August 2016, the OSMRE issued a Policy Advisory discouraging state regulatory authorities from approving self-bonding arrangements. The Policy Advisory indicated that the OSM would begin more closely reviewing instances in which states accept self-bonds for mining operations. In the same month, the OSM also announced that it was beginning the rulemaking process to strengthen regulations on self-bonding. In addition, surety bond costs have increased while the market terms of surety bondsbond have generally become less favorable. It is possible that surety bondsbond issuers may refuse to renew bonds or may demand additional collateral upon those renewals. Our failure to maintain, or inability to acquire, surety bonds that are required by state and federal laws would have a

material adverse effect on our ability to produce coal, which could affect our profitability and cash flow.

As of December 31, 2015,2018, we had approximately $58.5$42.6 million in surety bonds outstanding to secure the performance of our reclamation obligations. Of the $42.6 million, approximately $0.4 million relates to surety bonds for Deane Mining, LLC and approximately $3.4 million relates to surety bonds for Sands Hill Mining, LLC, which in each case have not been transferred or replaced by the buyers of Deane Mining, LLC or Sands Hill Mining, LLC as was agreed to by the parties as part of the transactions. We can provide no assurances that a surety company will underwrite the surety bonds of the purchasers of these entities, nor are we aware of the actual amount of reclamation at any given time. Further,ifthere was a claim under these surety bonds prior to the transfer or replacement of such bonds by the buyers of Deane Mining, LLC or Sands Hill Mining, LLC, then we may be responsible to the surety company for any amounts it pays in respect of such claim. While the buyers are required to increaseindemnify us for damages, including reclamation liabilities, pursuant the agreements governing the sales of these entities, we may not be successful in obtaining any indemnity or any amounts as a result of recent developments in West Virginia and Kentucky. In 2011, West Virginia passed legislation that provides for a minimum incremental bonding rate in lieu of a minimum bond amount that applies regardless of acreage. In addition, the Kentucky Department for Natural Resources and the Office of Surface Mining Reclamation and Enforcement Lexington Field Office executed an Action Plan for Improving the Adequacy of Kentucky Performance Bond Amounts, which provides for, among other things, revised bond computation protocols.received may be inadequate.

Air Emissions

The federal Clean Air Act (the "CAA"“CAA”) and similar state and local laws and regulations, which regulate emissions into the air, affect coal mining operations both directly and indirectly. The CAA directly impacts our coal mining and processing operations by imposing permitting requirements and, in some cases, requirements to install certain emissions control equipment, on sources that emit various hazardous and non-hazardous air pollutants. The CAA also indirectly affects coal mining operations by extensively regulating the air emissions of coal-fired electric power generating plants and other industrial consumers of coal, including air emissions of sulfur dioxide, nitrogen oxides, particulates, mercury and other compounds. There have been a series of recent federal rulemakings from the U.S. Environmental Protection Agency, or EPA, which are focused on emissions from coal-fired electric generating facilities. For example, Inin June 2015, the United States Supreme Court decided Michigan v. the EPA, which held that the EPA should have considered the compliance costs associated with its Mercury and Air Toxics Standards, or MATS, in deciding to regulate power plants under Section 112(n)(1) of the Clean Air Act. The Court did not vacate the MATS rule, and MATS has remained in place. In April 2016, EPA published its final supplemental finding that it remainsis “appropriate and necessary” to be seen what actionregulate coal and oil-fired units under Section 112 of the Clean Air Act. That finding was challenged in court, but the rule remained in effect. In April 2017, the D.C. Circuit Court of Appeals will take on remandagreed to conform its prior judgmentEPA’s request to delay proceedings while the Court's opinion. IfEPA reviewed the supplemental finding to determine whether it should be maintained, modified, or otherwise reconsidered. In December 2018, the EPA issued a proposed revised Supplemental Cost Finding for the MATS rule is vacated,proposing to determine that it is unclear hownot “appropriate and when the EPA might reevaluate its decisionnecessary” to regulate Hazardous Air Pollutant (“HAP”) emissions of mercury and other toxic pollutants from power plants in lightunder Section 112 of the Supreme Court's instructionClean Air Act. The EPA did not propose, however, to considerrescind or repeal the compliance costsHAP emission standards and other requirements of any such program pursuant to Section 112(n)(1); the EPA may re-propose the MATS rule, or otherwise pursue regulation of emissions of mercury and other toxic pollutants from power plantswhich would remain in place under the future. The MATS rule was expected to result in the retirement of certain older coal plants. It remains to be seen whether any such plants may reevaluate their decision to retire following the Supreme Court's decision, or whether plants that have already installed certain controls to comply with MATS will continue to operate them at all times.proposal. Installation of additional emissions control technology and additional measures required under laws and regulations related to air emissions will make it more costly to operate coal-fired power plants and possibly other facilities that consume coal and, depending on the requirements of individual state implementation plans, or SIPs, could make coal a less attractive fuel alternative in the planning and building of power plants in the future.

In addition to the greenhouse gas ("GHG"(“GHG”) regulations discussed below, air emission control programs that affect our operations, directly or indirectly, through impacts to coal-fired utilities and other manufacturing plants, include, but are not limited to, the following:

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The EPA's Acid Rain Program, provided in Title IV of the CAA, regulates emissions of sulfur dioxide from electric generating facilities. Sulfur dioxide is a by-product of coal combustion. Affected facilities purchase or are otherwise allocated sulfur dioxide emissions allowances, which must be surrendered annually in an amount equal to a facility's sulfur dioxide emissions in that year. Affected facilities may sell or trade excess allowances to other facilities that require additional allowances to offset their sulfur dioxide emissions. In addition to purchasing or trading for additional sulfur dioxide allowances, affected power facilities can satisfy the

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requirements of the EPA's Acid Rain Program by switching to lower sulfur fuels, installing pollution control devices such as flue gas desulfurization systems, or "scrubbers," or by reducing electricity generating levels.

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On July 6, 2011, the EPA finalized the Cross State Air Pollution Rule ("CSAPR"), which requires the District of Columbia and 27 states from Texas eastward (not including the New England states or Delaware) to significantly improve air quality by reducing power plant emissions that cross state lines and contribute to ozone and/or fine particle pollution in other states. Under the CSAPR, the first phase of the nitrogen oxide and sulfur dioxide emissions reductions was to commence in 2012 with further reductions effective in 2014. In October 2011, the EPA proposed amendments to the CSAPR to increase emission budgets in ten states, including Texas, and ease limits on market-based compliance options. While the CSAPR had an initial compliance deadline of January 1, 2012, the rule was challenged and, on December 30, 2011, the D.C. Circuit stayed the rule and advised that the EPA was expected to continue administering the Clean Air Interstate Rule until the pending challenges are resolved. The court vacated the CSAPR on August 21, 2012, in a two to one decision, concluding that the rule was beyond the EPA's statutory authority. The U.S. Supreme Court on April 29, 2014 reversed the D.C. Circuit and upheld the CSAPR, concluding generally that the EPA's development and promulgation of CSAPR was lawful, while acknowledging the possibility that under certain circumstances some states may have a basis to bring a particularized, as-applied challenge to the rule. In October 2014, the D.C. Circuit filed an order lifting its stay of CSAPR and addressing a number of preliminary motions regarding the implementation of the Supreme Court's remand. On remand, the D.C. Circuit court held on July 28, 2015 that certain of EPA's Phase II emission budgets were invalid because they required more emissions reductions than necessary to achieve the desired air pollutant reduction in the relevant downwind states. The court did not vacate the rule but required the EPA to reconsider the invalid emissions budgets.



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In addition, in January 2013, the EPA issued final MACT standards for several classes of boilers and process heaters, including large coal-fired boilers and process heaters (Boiler MACT), which require significant reductions in the emission of particulate matter, carbon monoxide, hydrogen chloride, dioxins and mercury. Business and environmental groups have filed legal challenges in federal appeals court and have petitioned EPA to reconsider the rule. EPA has granted petitions for reconsideration for certain issues promulgated a revised final rule in November 2015. The EPA retained a minimum carbon monoxide limit of 130 parts per million and the particulate matter continuous parameter monitoring system requirements, consistent with the January 2013 final rule, but made some minor changes to provisions related to boiler startup and shutdown practices. Legal challenges to the rule remain pending. However, if Boiler MACT is upheld as previously finalized, EPA estimates the rule will affect 1,700 existing major source facilities with an estimated 14,316 boilers and process heaters. Some owners will make capital expenditures to retrofit boilers and process heaters, while a number of boilers and process heaters will be prematurely retired. The retirements are likely to reduce the demand for coal. The impact of the regulations will depend on the outcome of these legal challenges and cannot be determined at this time.



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The EPA has adopted new, more stringent national air quality standards ("NAAQS") for ozone, fine particulate matter, nitrogen dioxide and sulfur dioxide. As a result, some states will be required to amend their existing SIPs to attain and maintain compliance with the new air quality standards. For example, in June 2010, the EPA issued a final rule setting forth a more stringent primary NAAQS applicable to sulfur dioxide. The rule also modifies the monitoring increment for the sulfur dioxide standard, establishing a 1-hour standard, and expands the sulfur dioxide monitoring network. Initial non-attainment determinations related to the 2010 sulfur dioxide rule were published in August 2013 with an effective date in October 2013. States with

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non-attainment areas had to submit their SIP revisions in April 2015, which must meet the modified standard by summer 2017. For all other areas, states will be required to submit "maintenance" SIPs. EPA finalized its PM2.5 NAAQS designations in December 2014. Individual states must now identify the sources of PM2.5 emissions and develop emission reduction plans, which may be state-specific or regional in scope. Nonattainment areas must meet the revised standard no later than 2021. More recently, in October 2015, the EPA lowered the NAAQS for ozone from 75 to 70 parts per billion for both the 8-hour primary and secondary standards. Significant additional emissions control expenditures will likely be required at coal-fired power plants and coke plants to meet the new standards. Because coal mining operations and coal-fired electric generating facilities emit particulate matter and sulfur dioxide, our mining operations and customers could be affected when the standards are implemented by the applicable states. Moreover, we could face adverse impacts on our business to the extent that these and any other new rules affecting coal-fired power plants result in reduced demand for coal.

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In June 2005, the EPA amended its regional haze program to improve visibility in national parks and wilderness areas. Affected states were required to develop SIPs by December 2007 that, among other things, identifies facilities that will have to reduce emissions and comply with stricter emission limitations. Implementation of this program may restrict construction of new coal-fired power plants where emissions are projected to reduce visibility in protected areas. In addition, this program may require certain existing coal-fired power plants to install emissions control equipment to reduce haze-causing emissions such as sulfur dioxide, nitrogen oxide, and particulate matter. Consequently, demand for our steam coal could be affected.

In addition, over the years, the Department of Justice, on behalf of the EPA, has filed lawsuits against a number of coal-fired electric generating facilities alleging violations of the new source review provisions of the CAA. The EPA has alleged that certain modifications have been made to these facilities without first obtaining certain permits issued under the new source review program. Several of these lawsuits have settled, but others remain pending. Depending on the ultimate resolution of these cases, demand for our coal could be affected.

Non-government organizations have also petitioned EPA to regulate coal mines as stationary sources under the Clean Air Act. On May 13, 2014, the D.C. Circuit in WildEarth Guardians v. United States Environmental Protection Agency upheld EPA'sEPA’s denial of one such petition. On July 18, 2014, the D.C. Circuit denied a petition to rehear that case en banc. We cannot guarantee that these groups will not make similar efforts in the future. If such efforts are successful, emissions of these or other materials associated with our mining operations could become subject to further regulation pursuant to existing laws such as the CAA. In that event, we may be required to install additional emissions control equipment or take other steps to lower emissions associated with our operations, thereby reducing our revenues and adversely affecting our operations.

Carbon Dioxide EmissionsClimate Change

One by-product of burning coal is carbon dioxide or CO₂, which EPA considers a GHG and a major source of concern with respect to climate change and global warming.

 Future regulation of GHG in the United States could occur pursuant to future U.S. treaty commitments, new domestic legislation that may impose a carbon emissions tax or establish a cap-and-trade program or regulation by the EPA. For example, on

On the international level, the United States iswas one of almost 200 nations that agreed on December 12, 2015 to an international climate change agreement in Paris, France, that calls for countries to set their own GHG emission targets and be transparent about the measures each country will use to achieve its GHG emission targets; however, the agreement does not set binding GHG emission reduction targets.

The Paris climate agreement entered into force in November 2016; however, in August 2017 the U.S. State Department officially informed the United Nations of the intent of the U.S. to withdraw from the agreement, with the earliest possible effective date of withdrawal being November 4, 2020. Despite the planned withdrawal, certain U.S. city and state governments have announced their intention to satisfy their proportionate obligations under the Paris Agreement. These commitments could further reduce demand and prices for coal.

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        Insteps to regulate GHG emissions. For example, in August 2015, the EPA issued its final Clean Power Plan (the "CPP"“CPP”) rules that establish carbon pollution standards for power plants, called CO₂emission performance rates. The EPA expects each state to develop implementation plans for power plants in its state to meet the individual state targets established in the CPP. The EPA has given states the option to develop compliance plans for annual rate-based reductions (pounds per megawatt hour) or mass-based tonnage limits for CO₂. The state plans are due in September 2016, subject to potential extensions of up to two years for final plan submission. The compliance period begins in 2022, and emission reductions will be phased in up to 2030. The EPA also proposed a federal compliance plan to implement the CPP in the event that an approvable state plan is not submitted to the EPA. Judicial challenges have been filed. On February 9, 2016,led the U.S. Supreme Court grantedto grant a stay of the implementation of the CPP before the United States Court of Appeals for the District of Columbia ("Circuit Court") even issued a decision.in February 2016. By its terms, this stay will remain in effect throughout the pendency of the appeals process including at the Circuit Court and the Supreme Court through any certiorari petition that may be granted. The stay suspends the rule, including the requirement that states submit their initial plans by September 2016.process. The Supreme Court'sCourt’s stay applies only to EPA'sEPA’s regulations for CO₂ emissions from existing power plants and will not affect EPA'sEPA’s standards for new power plants. It is not yet clear how the either the Circuit Court or the Supreme Courtcourts will rule on the legality of the CPP. Additionally, in October 2017 EPA proposed to repeal the CPP, although the final outcome of this action and the pending litigation regarding the CPP is uncertain at this time. In connection with the proposed repeal, EPA issued an Advance Notice of Proposed Rulemaking (“ANPRM”) in December 2017 regarding emission guidelines to limit GHG emissions from existing electricity utility generating units. In August 2018, the EPA issued the proposed Affordable Clean Energy (“ACE”) Rule, which would replace the CPP. If the ACE Rule is finalized, it will likely be subject to judicial challenge. If the effort to repeal the CPP is unsuccessful and the rules were upheld at the conclusion of thisthe appellate process and were implemented in their current form or if the ACE Rule results in state plans to reduce the level of GHG emissions from electric utility generating units, demand for coal will likely be further decreased. The EPA also issued a final rule for new coal-fired power plants in August 2015, which essentially set performance standards for coal-fired power plants that requires partial carbon capture and sequestration ("CCS"(“CCS”). Additional legal challenges have been filed against the EPA'sEPA’s rules for new power plants. The EPA'sEPA’s GHG rules for new and existing power plants, taken together, have the potential to severely reduce demand for coal. In addition, passage of any comprehensive federal climate change and energy legislation could impact the demand for coal. Any reduction in the amount of coal consumed by North American electric power generators could reduce the price of coal that we mine and sell, thereby reducing our revenues and materially and adversely affecting our business and results of operations.

Many states and regions have adopted greenhouse gas initiatives and certain governmental bodies have or are considering the imposition of fees or taxes based on the emission of greenhouse gases by certain facilities, including coal-fired electric generating facilities. For example, in 2005, ten northeastern states entered into the Regional Greenhouse Gas Initiative agreement ("RGGI"(“RGGI”) calling for implementation of a cap and trade program aimed at reducing carbon dioxide emissions from power plants in the participating states. The members of RGGI have established in statute and/or regulation a carbon dioxide trading program. Auctions for carbon dioxide allowances under the program began in September 2008. Though New Jersey withdrew from RGGI in 2011, since its inception, several additional northeastern states and Canadian provinces have joined as participants or observers.

Following the RGGI model, five Western states launched the Western Regional Climate Action Initiative to identify, evaluate and implement collective and cooperative methods of reducing greenhouse gases in the region to 15% below 2005 levels by 2020. These states were joined by two additional states and four Canadian provinces and became collectively known as the Western Climate Initiative Partners. However, in November 2011, six states withdrew, leaving California and the four Canadian provinces as members. At a January 12, 2012 stakeholder meeting, this group confirmed a commitment and timetable to create the largest carbon market in North America and provide a model to guide future efforts to establish national approaches in both Canada and the U.S. to reduce GHG emissions. It is likely that these regional efforts will continue.

Many coal-fired plants have already closed or announced plans to close and proposed new construction projects have also come under additional scrutiny with respect to GHG emissions. There have been an increasing number of protests and challenges to the permitting of new coal-fired power

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plants by environmental organizations and state regulators fordue to concerns related to greenhouse gas emissions. Other state regulatory authorities have also rejected the construction of new coal-fueled power plants based on the uncertainty surrounding the potential costs associated with GHG emissions from these plants under future laws limiting the emissions of carbon dioxide. In addition, several permits issued to new coal-fired power plants without limits on GHG emissions have been appealed to the EPA'sEPA’s Environmental Appeals Board. In addition, over 30 states have adopted mandatory "renewable“renewable portfolio standards,"” which require electric utilities to obtain a certain percentage of their electric generation portfolio from renewable resources by a certain date. These standards range generally from 10% to 30%, over time periods that generally extend from the present until between 2020 and 2030. Other states may adopt similar requirements, and federal legislation is a possibility in this area. To the extent these requirements affect our current and prospective customers;customers, they may reduce the demand for coal-fired power, and may affect long-term demand for our coal.

If mandatory restrictions on carbon dioxideCO₂ emissions are imposed, the ability to capture and store large volumes of carbon dioxide emissions from coal-fired power plants may be a key mitigation technology to achieve emissions reductions while meeting projected energy demands. A number of recent legislative and regulatory initiatives to encourage the development and use of carbon capture and storage technology have been proposed or enacted. On February 3, 2010, President Obama sentFor example, in October 2015, the EPA released a memorandum torule that established, for the heads of fourteen Executive Departments and Federal Agencies establishing an Interagency Task Force on Carbon Capture and Storage ("CCS"). The goal was to develop a comprehensive and coordinated Federal strategy to speed the commercial development and deployment of clean coal technologies. On August 12, 2010, the Task Force delivered a series of recommendations on overcoming the barriers to the widespread, cost-effective deployment of CCS within ten years. The report concludes that CCS can play an important role in domestic GHG emissions reductions while preserving the option of using abundant domestic fossil energy resources. The EPA also recently proposedfirst time, new source performance standards under the federal Clean Air Act for GHG forCO₂ emissions from new coal and oil-firedfossil fuel-fired electric utility generating power plants, which could requireplants. The EPA has designated partial carbon capture and sequestration as the best system of emission reduction for newly constructed fossil fuel-fired steam generating units at power plants to comply.employ to meet the standard. However, widespread cost-effective deployment of CCS will occur only if the technology is commercially available at economically competitive prices and supportive national policy frameworks are in place.

There have also been attempts to encourage greater regulation of coalbed methane because methane has a greater GHG effect than CO2. Methane from coal mines can give rise to safety concerns, and may require that various measures be taken to mitigate those risks. If new laws or regulations were introduced to reduce coalbed methane emissions, those rules could adversely affect our costs of operations.

These and other current or future global climate change laws, regulations, court orders or other legally enforceable mechanisms, or related public perceptions regarding climate change, are expected to require additional controls on coal-fired power plants and industrial boilers and may cause some users of coal to further switch from coal to alternative sources of fuel, thereby depressing demand and pricing for coal.

Finally, some scientists have warned that increasing concentrations of greenhouse gases (“GHGs”) in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events. If these warnings are correct, and if any such effects were to occur in areas where we or our customers operate, they could have an adverse effect on our assets and operations.

Clean Water Act

The Federal Clean Water Act (the "CWA"“CWA”) and similar state and local laws and regulations affect coal mining operations by imposing restrictions on the discharge of pollutants, including dredged or fill material, into waters of the U.S. The CWA establishes in-stream water quality and treatment standards for wastewater discharges that are applied to wastewater dischargers through Section 402 National Pollutant Discharge Elimination System ("NPDES"(“NPDES”) permits. Regular monitoring, as well as compliance with reporting requirements and performance standards, are preconditions for the issuance and renewal of Section 402 NPDES permits. Individual permits or general permits under Section 404 of the CWA are required to discharge dredged or fill materials into waters of the U.S. including wetlands, streams, and other areas meeting the regulatory definition. Expansion of EPA jurisdiction over these areas has the potential to adversely impact our operations. For example,Considerable legal uncertainty exists surrounding the standard for what constitutes jurisdictional waters and wetlands subject to the protections and requirements of the Clean Water Act. A 2015 rulemaking by EPA to revise the standard was stayed nationwide by the U.S. Court of Appeals for the Sixth Circuit and stayed for certain primarily western states by a United States District Court in North Dakota. In January 2018, the Supreme Court determined that the circuit courts do not have jurisdiction to hear challenges to the 2015 rule, removing the basis for the Sixth Circuit to continue its nationwide stay. In February 2018, the EPA releasedand the U.S. Army Corps of Engineers (the “Corps”) published a final rule extending the applicability date of the 2015 rule such that the rule would not be applicable until February 2020. In August 2018, the U.S. District Court for the District of South Carolina invalidated the two-year nationwide delay of the rule, leaving the 2015 rule in Mayeffect in 26 states, while the pre-2015 regulations and guidance continue to apply in 24 states. In December 2018, the EPA and the Corps proposed a new definition of “waters of the United States.” Judicial challenges to the 2015 that attemptedrulemaking are likely to clarify federal jurisdiction undercontinue to work their way through the CWA over waterscourts along with challenges to the more recent rulemaking extending the applicability date of the 2015 rule. The agencies’ efforts to repeal the 2015 rule and to revise the definition of “waters of the United States” will also likely be subject to lengthy judicial challenges. For now, EPA and the Corps are complying with the South Carolina District Court’s order in the 26 states in which it applies. Should the 2015 rule be enforced in the states in which we operate, or should a different rule expanding the definition of what constitutes a water of the United States butbe finalized as a numberresult of legal challenges to this rule are pending,EPA and implementation of the rule has been stayed nationwide. To the extent the rule expands the scope of the CWA's jurisdiction,Corps’s rulemaking process, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas.

Our surface coal mining and preparation plant operations typically require such permits to authorize activities such as the creation of slurry ponds, stream impoundments, and valley fills. The EPA, or a state that has been delegated such authority by the EPA, issues NPDES permits for the discharge of pollutants into navigable waters, while the U.S. Army Corps of Engineers (the "Corps"“Corps”) issues dredge and fill permits under Section 404 of the CWA. Where Section 402 NPDES permitting authority has been delegated to a state, the EPA retains a limited oversight role. The CWA also gives the EPA an

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oversight role in the Section 404 permitting program, including drafting substantive rules governing permit issuance by the Corps, providing comments on proposed permits, and, in some cases, exercising the authority to delay or pre-empt Corps issuance of a Section 404 permit. The EPA has recently asserted these authorities more forcefully to question, delay, and prevent issuance of some Section 402 and 404 permits for surface coal mining in Appalachia. Currently, significant uncertainty exists regarding the obtaining of permits under the CWA for coal mining operations in Appalachia due to various initiatives launched by the EPA regarding these permits.

For instance, even though the Commonwealth of Kentucky and the State of West Virginia have been delegated the authority to issue NPDES permits for coal mines in those states, the EPA is taking a more active role in its review of NPDES permit applications for coal mining operations in Appalachia. The EPA issued final guidance on July 21, 2011 that encouraged EPA Regions 3, 4 and 5 to object to the issuance of state program NPDES permits where the Region does not believe that the proposed permit satisfies the requirements of the CWA and with regard to state issued general Section 404 permits, support the previously drafted Enhanced Coordination Process ("ECP"(“ECP”) among the EPA, the Corps, and the U.S. Department of the Interior for issuing Section 404 permits, whereby the EPA undertook a greater level of review of certain Section 404 permits than it had previously undertaken. The D.C. Circuit upheld EPA'sEPA’s use of the ECP in July 2014. Future application of the ECP, such as may be enacted following notice and comment rulemaking, would have the potential to delay issuance of permits for surface coal mines, or to change the conditions or restrictions imposed in those permits.

The EPA also has statutory "veto"“veto” power under Section 404(c) to effectively revoke a previously issued Section 404 permit if the EPA determines, after notice and an opportunity for a public hearing, that the permit will have an "unacceptable“unacceptable adverse effect." On January 14, 2011,” The Court previously upheld the EPA exercised its Section 404(c) authorityEPA’s ability to withdraw or restrict the use of a previously issued permit for the Spruce No. 1 Surface Mine in West Virginia, which is one of the largest surface mining operations ever authorized in Appalachia. This action was the first time that such power was exercised with regard to a previously permitted coal mining project. A challenge to the EPA's exercise of this authority was made in the federal District Court in the District of Columbia and on March 23, 2012, the Court ruled that the EPA lacked the statutory authority to invalidate an already issued Section 404 permit retroactively. This decision was appealed and reversed by the D.C. Circuit Court of Appeals in April 2013, finding that EPA has the authority to issue a retroactive veto, but remanding for consideration of whether that decision was arbitrary and capricious. The mining company has also petitioned the U.S. Supreme Court for certiorari to overturn the ruling. The Supreme Court denied certiorari in March 2014. .Any future use of the EPA'sEPA’s Section 404 "veto"“veto” power could create uncertainty with regard to our or our lessees' continued use of their current permits, as well as impose additional time and cost burdens on future operations, potentially adversely affecting our coal royalties revenues.

The Corps is authorized to issue general "nationwide"“nationwide” permits for specific categories of activities that are similar in nature and that are determined to have minimal adverse environmental effects. We may no longer seek general permits under Nationwide Permit 21 ("(“NWP 21"21”) because in February 2012, the Corps reinstated the use of NWP 21, but limited application of NWP 21 authorizations to discharges with impacts not greater than a half-acre of water, including no more than 300 linear feet of streambed, and disallowed the use of NWP 21 for valley fills. This limitation remains in place in the NWP 21 issued in January of 2017. If the newly issued2017 NWP 21 cannot be used for any of our proposed surface coal mining projects, we will have to obtain individual permits from the Corps subject to the additional EPA measures discussed below with the uncertainties and delays attendant to that process.

We currently have a number of Section 404 permit applications pending with the Corps. Not all of these permit applications seek approval for valley fills or other obvious "fills"“fills”; some relate to other activities, such as mining through streams and the associated post-mining reconstruction efforts. We sought to prepare all pending permit applications consistent with the requirements of the Section 404

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program. Our five year plan of mining operations does not rely on the issuance of these pending permit applications. However, the Section 404 permitting requirements are complex, and regulatory scrutiny of these applications, particularly in Appalachia, has increased such that our applications may not be granted or, alternatively, the Corps may require material changes to our proposed operations before it grants permits. While we will continue to pursue the issuance of these permits in the ordinary course of our operations, to the extent that the permitting process creates significant delay or limits our ability to pursue certain reserves beyond our current five year plan, our revenues may be negatively affected.

Total Maximum Daily Load ("TMDL"(“TMDL”) regulations under the CWA establish a process to calculate the maximum amount of a pollutant that an impaired water body can receive and still meet state water quality standards, and to allocate pollutant loads among the point- and non-point pollutant sources discharging into that water body. Likewise, when water quality in a receiving stream is better than required, states are required to conduct an anti-degradation review before approving discharge permits. The adoption of new TMDLs and load allocations or any changes to anti-degradation policies for streams near our coal mines could limit our ability to obtain NPDES permits, require more costly water treatment, and adversely affect our coal production.

 In addition, in May 2014, EPA issued a new final rule pursuant to Section 316(b) of the CWA that affects the cooling water intake structures at power plants in order to reduce fish impingement and entrainment. The rule is expected to affect over 500 power plants. These requirements could increase our customers' costs and cause them to reduce their demand for coal, which may materially impact our results or operations.

Hazardous Substances and Wastes

The federal Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"(“CERCLA”), also known as the "Superfund"“Superfund” law, and analogous state laws, impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a "hazardous substance"“hazardous substance” into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and several liabilities for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources. Some products used by coal companies in operations generate waste containing hazardous substances. We are not aware of any material liability associated with the release or disposal of hazardous substances from our past or present mine sites.

The federal Resource Conservation and Recovery Act ("RCRA"(“RCRA”) and corresponding state laws regulating hazardous waste affect coal mining operations by imposing requirements for the generation, transportation, treatment, storage, disposal and cleanup of hazardous wastes. Many mining wastes are excluded from the regulatory definition of hazardous wastes, and coal mining operations covered by SMCRA permits are by statute exempted from RCRA permitting. RCRA also allows the EPA to require corrective action at sites where there is a release of hazardous wastes. In addition, each state has its own laws regarding the proper management and disposal of waste material. While these laws impose ongoing compliance obligations, such costs are not believed to have a material impact on our operations.

 In June 2010, EPA released a proposed rule to regulate the disposal of certain coal combustion by-products ("CCB"). The proposed rule sets forth two proposed avenues for the regulation of CCB under RCRA. The first option called for regulation of CCB under Subtitle C as a hazardous waste, which creates a comprehensive program of federally enforceable requirements for waste management and disposal. The second option called for regulation of CCB under Subtitle D as a solid waste, which

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gives EPA authority to set performance standards for solid waste management facilities and would be enforced primarily through state agencies and citizen suits. In December 2014, EPA finalized regulations that address the management of coal ash as a non-hazardous solid waste under Subtitle D. The rules impose engineering, structural and siting standards on surface impoundments and landfills that hold coal combustion wastes and mandate regular inspections. The rule also requires fugitive dust controls and imposes various monitoring, cleanup, and closure requirements. The rule leaves intact the Bevill exemption for beneficial uses of CCB, though it defers a final Bevill regulatory determination with respect to CCB that is disposed of in landfills or surface impoundments. Additionally, in December 2016, Congress passed the Water Infrastructure Improvements for the Nation Act, which provides for the establishment of state and EPA permit programs for the control of coal combustion residuals and authorizes states to incorporate EPA’s final rule for coal combustion residuals or develop other criteria that are at least as protective as the final rule. The costs of complying with these new requirements may result in a material adverse effect on our business, financial condition or results of operations, and could potentially increase our customers'customers’ operating costs, thereby reducing their ability to purchase coal as a result. In addition, contamination caused by the past disposal of CCB, including coal ash, can lead to material liability to our customers under RCRA or other federal or state laws and potentially reduce the demand for coal.

Endangered Species Act

The federal Endangered Species Act and counterpart state legislation protect species threatened with possible extinction. Protection of threatened and endangered species may have the effect of prohibiting or delaying us from obtaining mining permits and may include restrictions on timber harvesting, road building and other mining or agricultural activities in areas containing the affected species or their habitats. A number of species indigenous to our properties are protected under the Endangered Species Act. Based on the species that have been identified to date and the current application of applicable laws and regulations, however, we do not believe there are any species protected under the Endangered Species Act that would materially and adversely affect our ability to mine coal from our properties in accordance with current mining plans.

Use of Explosives

We use explosives in connection with our surface mining activities. The Federal Safe Explosives Act ("SEA"(“SEA”) applies to all users of explosives. Knowing or willful violations of the SEA may result in fines, imprisonment, or both. In addition, violations of SEA may result in revocation of user permits and seizure or forfeiture of explosive materials.

The storage of explosives is also subject to regulatory requirements. For example, pursuant to a rule issued by the Department of Homeland Security in 2007, facilities in possession of chemicals of interest (including ammonium nitrate at certain threshold levels) are required to complete a screening review in order to help determine whether there is a high level of security risk, such that a security vulnerability assessment and a site security plan will be required. It is possible that our use of explosives in connection with blasting operations may subject us to the Department of Homeland Security's newSecurity’s chemical facility security regulatory program.

The costs of compliance with these requirements should not have a material adverse effect on our business, financial condition or results of operations.

In January 2015,December 2014, OSM announced its decision to propose a rule that it intends to pursuewill address all blast generated fumes and toxic gases. OSM has not yet issued a rulemakingproposed rule to address clouds of nitrogen oxide associated with blasting operations pursuant to a petition by a nongovernmental organization.these blasts. We are unable to predict the impact, if any, of these actions by the OSM, although the actions potentially could result in additional delays and costs associated with our blasting operations.

Other Environmental and Mine Safety Laws

We are required to comply with numerous other federal, state and local environmental and mine safety laws and regulations in addition to those previously discussed. These additional laws include, for example, the Safe Drinking Water Act, the Toxic Substance Control Act and the Emergency Planning

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and Community Right-to-Know Act. The costs of compliance with these requirements is not expected to have a material adverse effect on our business, financial condition or results of operations.

Federal Power Act – Grid Reliability Proposal

Pursuant to a direction from the Secretary of the Department of Energy, the Federal Energy Regulatory Commission (“FERC”) issued a notice of proposed rulemaking under the Federal Power Act regarding the valuation by regional electric grid system operators of the reliability and resilience attributes of electricity generation. The rulemaking would have required the FERC to impose market rules that would allow certain cost recovery by electricity-generating units that maintain a 90-day fuel supply on-site and that are therefore capable of providing electricity during supply disruptions from emergencies, extreme weather or natural or man-made disasters. Many coal-fired electricity generating plants could have qualified under this criteria and the cost recovery could have helped improve the economics of their operations. However, in January 2018, the FERC terminated the proposed rulemaking, finding that it failed to satisfy the legal requirements of section 206 of the Federal Power Act, and initiated a new proceeding to further evaluate whether additional FERC action regarding resilience is appropriate. Should a version of this rule be adopted in the future along the lines originally proposed, it could provide economic incentives for companies that produce electricity from coal, among other fuels, which could either slow or stabilize the trend in the shuttering of coal-fired power plants and could thereby maintain certain levels of domestic demand for coal. We cannot speculate on the timing or nature of any subsequent FERC or grid operator actions resulting from the FERC’s decision to further study the issue of grid resiliency.

Employees

To carry out our operations, our general partner and our subsidiaries employed 551701 full-time employees as of December 31, 2015.2018. None of the employees are subject to collective bargaining agreements. We believe that we have good relations with these employees and since our inception we have had no history of work stoppages or union organizing campaigns.

Available Information

Our internet address ishttp://www.rhinolp.com, and we make available free of charge on our website our Annual Reports on Form 10-K, our Quarterly Reports on Form 10-Q, our Current Reports on Form 8-K and Forms 3, 4 and 5 for our Section 16 filers (and amendments and exhibits, such as press releases, to such filings) as soon as reasonably practicable after we electronically file with or furnish such material to the SEC. Also included on our website are our "Code“Code of Business Conduct and Ethics"Ethics”, our "Insider“Insider Trading Policy," "Whistleblower Policy"” “Whistleblower Policy” and our "Corporate“Corporate Governance Guidelines"Guidelines” adopted by the board of directors of our general partner and the charters for the Audit Committee and Compensation Committee. Information on our website or any other website is not incorporated by reference into this report and does not constitute a part of this report.

We file or furnish annual, quarterly and current reports and other documents with the SEC under the Securities Exchange Act of 1934 (the "Exchange Act"“Exchange Act”). The public may read and copy any materials that we file with the SEC at the SEC's Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Additionally, the SEC'sSEC’s website,http://www.sec.gov, contains reports, proxy and information statements, and other information regarding issuers, including us, that file electronically with the SEC.

Item 1A. Risk Factors.

In addition to the factors discussed elsewhere in this report, including the financial statements and related notes, you should consider carefully the risks and uncertainties described below. If any of these risks or uncertainties, as well as other risks and uncertainties that are not currently known to us or that we currently believe are not material, were to occur, our business, financial condition or results of operation could be materially adversely affected and you may lose all or a significant part of your investment.

Risks Inherent in Our Business

As we have been unable to extend the expiration date of our amended and restated credit agreement, we are unable to demonstrate that we have sufficient liquidity to operate our business over the next twelve months and thus substantial doubt is raised about our ability to continue as a going concern. Accordingly, our independent registered public accounting firm has included an emphasis paragraph with respect to our ability to continue as a going concern in its report on our consolidated financial statements for the year ended December 31, 2015.

        As we have been unable to extend the expiration date of our amended and restated credit agreement, we are unable to demonstrate that we have sufficient liquidity to operate our business over the next twelve months and thus substantial doubt is raised about our ability to continue as a going concern. Accordingly, our independent registered public accounting firm has included an emphasis paragraph with respect to our ability to continue as a going concern in its report on our consolidated financial statements for the year ended December 31, 2015. The presence of the going concern emphasis paragraph in our auditors' report may have an adverse impact on our relationship with third

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parties with whom we do business, including our customers, vendors, lenders and employees, making it difficult to raise additional debt or equity financing to the extent needed and conduct normal operations. As a result, our business, results of operations, financial condition and prospects could be materially adversely affected.

        In April 2015, we entered into a third amendment of our amended and restated senior secured credit facility. The third amendment extended the expiration date of the amended and restated credit agreement to July 2017. The extension was contingent upon (i) our leverage ratio being less than or equal to 2.75 to 1.0 and (ii) our having liquidity greater than or equal to $15 million, in each case for either the quarter ending December 31, 2015 or March 31, 2016. If both of these conditions were not satisfied for either quarter, the expiration date of the amended and restated credit agreement would revert to July 2016, at which time we will be required to repay all of the outstanding borrowings thereunder. As of December 31, 2015, our leverage ratio was 3.2 to 1.0 and our liquidity was approximately $1.1 million. Thus, we did not meet the extension conditions as of December 31, 2015. In March 2016, we amended our amended and restated senior secured credit facility where the expiration date was set to July 2016. We are working with our lenders to extend the amended and restated credit agreement to December 2017. Since our credit facility has an expiration date of July 2016, we determined that our credit facility debt liability of $41.2 million at December 31, 2015 should be classified as a current liability on our consolidated statements of financial position. The classification of our credit facility balance as a current liability raises substantial doubt of our ability to continue as a going concern for the next twelve months. If we are unable to amend and extend the expiration date of our amended and restated senior secured credit facility, we will have to secure alternative financing to replace our credit facility by the expiration date of July 2016 in order to continue our business operations, and there can be no assurance that we would be able to obtain adequate alternative financing on acceptable terms or at all.

        There are other uncertainties as to our ability to access funding under our amended and restated credit agreement. In order to borrow under our amended and restated credit facility, we must make certain representations and warranties to our lenders at the time of each borrowing. If we are unable to make these representations and warranties, we would be unable to borrow under our amended and restated credit facility, absent a waiver. Furthermore, if we violate any of the covenants or restrictions in our amended and restated credit agreement, including the maximum leverage ratio, some or all of our indebtedness may become immediately due and payable, and our lenders' commitment to make further loans to us may terminate. Given the continued weak demand and low prices for met and steam coal, we may not be able to continue to give the required representations or meet all of the covenants and restrictions included in our credit facility. If we are unable to give a required representation or we violate a covenant or restriction, then we will need a waiver from our lenders in order to continue to borrow under our amended and restated credit agreement.

        Our principal liquidity requirements are to finance current operations, fund capital expenditures and service our debt. Our principal sources of liquidity are cash generated by our operations and borrowings under our credit facility. If we are unable to extend the expiration date of our amended and restated credit facility or secure a replacement facility or borrow under our existing credit facility, we will lose a primary source of liquidity, and we may not be able to generate adequate cash flow from operations to fund our business, including amounts that may become due under our credit facility. Failure to obtain financing or to generate sufficient cash flow from operations could cause us to further curtail our operations and reduce our spending and to alter our business plan. We may also be required to consider other options, such as selling additional assets or merger opportunities, and depending on the urgency of our liquidity constraints, we may be required to pursue such an option at an inopportune time. If we are not able to fund our liquidity requirements for the next twelve months, we may not be able to continue as a going concern.

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Our common units have been suspended from trading on the NYSE and may cease to be listed on the NYSE should we lose the appeal of the suspension and delisting of our common units. Furthermore, even if we were to successfully appeal the suspension and delisting of our common units from the NYSE, we may be unable to maintain compliance with the NYSE continued listing requirements.

        On December 17, 2015, the NYSE notified us that it had determined to commence proceedings to delist our common units from the NYSE as a result of our failure to comply with the continued listing standard set forth in Section 802.01B of the NYSE Listed Company Manual to maintain an average global market capitalization over a consecutive 30 trading-day period of at least $15 million for its common units. The NYSE also suspended the trading of the common units at the close of trading on December 17, 2015. Following the suspension, our common units began trading on the OTCQB under the symbol "RHNO" on December 18, 2015. The NYSE informed us that it will apply to the Securities and Exchange Commission to delist our common units upon completion of all applicable procedures, including any appeal by us of the NYSE's decision. On January 4, 2016, we filed an appeal with the NYSE to review the suspension and delisting determination of our common units. The NYSE notified us that our appeal would be reviewed on April 20, 2016 to make a determination on the suspension and delisting of our common units. There can be no assurance that we will be successful in our appeal and that our request for continued listing on the NYSE will be granted. Furthermore, even if we were to successfully appeal the suspension and delisting of our common units from the NYSE, we may be unable to maintain compliance with the NYSE continued listing requirements.

        A delisting of our common units from the NYSE as a result of an unsuccessful appeal could negatively impact us by, among other things, reducing the liquidity and market price of our common units; reducing the number of investors willing to hold or acquire our common units; and limiting our ability to issue additional securities or obtain additional financing. Further, if our common units are delisted from the NYSE, we would no longer be subject to the NYSE rules including rules requiring us to meet certain corporate governance standards. Without required compliance of these corporate governance standards, investor interest in our common units may decrease.

Our common units are currently traded on the OTCQB as a result of the NYSE's suspension of trading ofNYSE’s delisting our common units. In the event of an unsuccessful appeal of the suspension and delisting of our common units from the NYSE, our common units will be delisted from the NYSE and will trade indefinitely on the OTCQB or one of the other over-the-counter markets, which could adversely affect the market liquidity of our common units and harm our business.

Our common units were suspended from trading on the NYSE at the close of trading on December 17, 2015. On December 18, 2015 ourand delisted from the NYSE on May 9, 2016. Our common units began trading over the countertrade on the OTCQB under the ticker symbol "RHNO." On January 4, 2016, we filed an appeal with the NYSE to review the suspension and delisting determination of our“RHNO.” The common units. While our appeal is pending, the common units will remain suspended from trading on the NYSE and will continue to trade on the OTCQB or one of the other over-the-counter markets.

Trading on the OTCQB or one of the other over-the-counter markets may result in a reduction in some or all of the following, each of which could have a material adverse effect on our unitholders:

•

the liquidity of our common units;



•

the market price of our common units;



•

our ability to issue additional securities or obtain financing;



•

	●	the liquidity of our common units;
	●	the market price of our common units;
	●	our ability to issue additional securities or obtain financing;
	●	the number of institutional and other investors that will consider investing in our common units;
	●	the number of market makers in our common units;
	●	the availability of information concerning the trading prices and volume of our common units; and
	●	the number of broker-dealers willing to execute trades in our common units.

Further, since our common units were delisted from the NYSE, we are no longer subject to the NYSE rules including rules requiring us to meet certain corporate governance standards. Without required compliance of these corporate governance standards, investor interest in our common units;



•

the number of market makers in our common units;

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•

the availability of information concerning the trading prices and volume of our common units; and



•

the number of broker-dealers willing to execute trades in our common units.

We may not have sufficient cash to enable us to pay the minimum quarterly distribution on our common units following establishment of cash reserves and payment of costs and expenses, including reimbursement of expenses to our general partner.

We may not have sufficient cash each quarter to pay the full amount of our minimum quarterly distribution of $0.445$4.45 per unit, or $1.78$17.80 per unit per year, which will require us to have available cash of approximately $13.3$58.6 million per quarter, or $53.2$234.2 million per year, based on the number of common and subordinated units outstanding as of December 31, 20152018 and the general partner interest. The amount of cash we can distribute on our common and subordinated units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

•

the amount of coal we are able to produce from our properties, which could be adversely affected by, among other things, operating difficulties and unfavorable geologic conditions;



•

the price at which we are able to sell coal, which is affected by the supply of and demand for domestic and foreign coal;



•

the level of our operating costs, including reimbursement of expenses to our general partner and its affiliates. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed;



•

the proximity to and capacity of transportation facilities;



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the price and availability of alternative fuels;



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the impact of future environmental and climate change regulations, including those impacting coal-fired power plants;



•

the level of worldwide energy and steel consumption;



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prevailing economic and market conditions;



•

difficulties in collecting our receivables because of credit or financial problems of customers;



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the effects of new or expanded health and safety regulations;



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domestic and foreign governmental regulation, including changes in governmental regulation of the mining industry, the electric utility industry or the steel industry;



•

changes in tax laws;



•

weather conditions; and



•

force majeure.

We may reduce or eliminate distributions at any time we determine that our cash reserves are insufficient or are otherwise required to fund current or anticipated future operations, capital expenditures, acquisitions, growth or expansion projects, debt repayment or other business needs. Beginning with the quarter ended September 30, 2014, distributions on our common units were below the minimum level and, beginning with the quarter ended June 30, 2015, we suspended the quarterly distribution on our common units altogether. Pursuant to our partnership agreement, our common units accrue arrearages every quarter when the distribution level is below the minimum quarterly distribution level and our subordinated units do not accrue such arrearages. In the future, if and as

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distributions are made for any quarter, the first priority is to pay the then minimum quarterly distribution to common unitholders. Any additional distribution amounts paid at that time are then paid to common unitholders until previously unpaid accumulated arrearage amounts have been paid in full. Thus, we have arrearages accumulating on our common units since the distribution level has been below our minimum quarterly level of $0.445$4.45 per unit. In addition, we have not paid any distributions on our subordinated units for any quarter after the quarter ended March 31, 2012. We may not have sufficient cash available for distributions on our common or subordinated units in the future. Any further reduction in the amount of cash available for distributions could impact our ability to pay any quarterly distribution on our common units. Moreover, we may not be able to increase distributions on our common units if we are unable to pay the accumulated arrearages on our common units as well as the full minimum quarterly distribution on our subordinated units.

A decline in coal prices could adversely affect our results of operations and cash available for distribution to our unitholders.

Our results of operations and the value of our coal reserves are significantly dependent upon the prices we receive for our coal as well as our ability to improve productivity and control costs. Prices for coal tend to be cyclical; however, prices have become more volatile and depressed as a result of oversupply in the marketplace.cyclical. The prices we receive for coal depend upon factors beyond our control, including:

•

the supply of domestic and foreign coal;



•

the demand for domestic and foreign coal, which is significantly affected by the level of consumption of steam coal by electric utilities and the level of consumption of metallurgical coal by steel producers;



•

the price and availability of alternative fuels for electricity generation;



•

the proximity to, and capacity of, transportation facilities;



•

domestic and foreign governmental regulations, particularly those relating to the environment, climate change, health and safety;



•

the level of domestic and foreign taxes;



•

weather conditions;



•

terrorist attacks and the global and domestic repercussions from terrorist activities; and



•

prevailing economic conditions.

Any adverse change in these factors could result in weaker demand and lower prices for our products. In addition, the recent global economic downturn, coupled with the global financial and credit market disruptions hashave historically had an impact on the coal industry generally and may continue to do so. The demand for electricity and steel may remain at low levels or further decline if economic conditions remain weak.weaken. If these trends continue,electricity and steel demand weaken, we may not be able to sell all of the coal we are capable of producing or sell our coal at prices comparable to recent years.acceptable prices.

In addition to competing with other coal producers, we compete generally with producers of other fuels, such as natural gas. A decline in the price of natural gas has made natural gas more competitive against coal and resulted in utilities switching from coal to natural gas. Sustained low natural gas prices may also cause utilities to phase out or close existing coal-fired power plants or reduce or eliminate construction of any new coal-fired power plants, which could have a material adverse effect on demand and prices received for our coal. A substantial or extended decline in the prices we receive for our coal supply contracts could materially and adversely affect our results of operations.

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        As the prolonged weakness in the U.S. coal markets continued during 2015, weWe performed a comprehensive review during the fourth quarter of 2015 of our current coal mining operationsoperation as well as potential future development projects for the year ended December 31, 2018 to ascertain any potential impairment losses. We identified variousdid not record any impairment losses for coal properties, projects and operations that were potentially impaired based upon changes in its strategic plans, market conditionsmine development costs or other factors, specifically in Northern Appalachia where market conditions related to our operations deteriorated in the fourth quarter of 2015. We believe that an oversupply of coal being produced in Northern Appalachia has contributed to depressed coal prices from this region. We believe the oversupply of coal has been created due to historically low natural gas prices in this region, which competes with coal as a source of electricity generation. Utilities have chosen cheap natural gas for electricity generation over coal and, additionally, we believe the amount that the utilities' power plants have been dispatched for electricity generation has fallen due to low electricity demand. The production of natural gas from the Utica Shale and Marcellus Shale regions that are located within the Northern Appalachian region have kept natural gas prices low and larger coal producers have low-cost long-wall mines in Northern Appalachia that can compete to sell lower priced coal to utilities that still require coal supplies in this region. We believe this combination of factors have decreased coal prices in Northern Appalachia to levels where certain current operations as well as future plans for the development of the Leesville Field will be unprofitable in the near term. In addition to impairment charges related to certain Northern Appalachia operations, we also recorded asset impairmentmining equipment and related charges for the sale of the Deane mining complex, the sale of our Cana Woodford oil and natural gas investment and an impairment charge for intangible assets. We recorded approximately $31.6 million of total asset impairment and related chargesfacilities for the year ended December 31, 2015. Please see "Part II, Item 7. Management's Discussion and Analysis2018.

We performed a comprehensive review of Financial Condition and Resultsour current coal mining operation as well as potential future development projects for the year ended December 31, 2017 to ascertain any potential impairment losses. We engaged an independent third party to perform a fair market value appraisal on certain parcels of Operations"land that we own in Mesa County, Colorado. The parcels appraised for a detailed discussion$6.0 million compared to the carrying value of these asset$6.8 million. We recorded an impairment loss of $0.8 million, which is recorded on the Asset impairment and related charges.charges line of the consolidated statements of operations and comprehensive income. No other coal properties, mine development costs or other coal mining equipment and related facilities were impaired as of December 31, 2017.

 In addition,

We also recorded an impairment charge of $21.8 million related to the pricescall option received from a third party to acquire substantially all of oil and natural gas may fluctuate widely in response to relatively minor changesthe outstanding common stock of Armstrong Energy, Inc. On October 31, 2017, Armstrong Energy filed Chapter 11 petitions in the supplyEastern District of Missouri’s United States Bankruptcy Court. Per the Chapter 11 petitions, Armstrong Energy filed a detailed restructuring plan as part of the Chapter 11 proceedings. On February 9, 2018, the U.S. Bankruptcy Court confirmed Armstrong Energy’s Chapter 11 reorganization plan and demand for oilas such we concluded that the call option had no carrying value. An impairment charge of $21.8 million related to the call option was recorded on the Asset impairment and natural gas, market uncertaintyrelated charges line of the consolidated statements of operations and a variety of additional factors that are beyond our control.comprehensive income.

We could be negatively impacted by the competitiveness of the global markets in which we compete and declines in the market demand for coal.

We compete with coal producers in various regions of the United States and overseas for domestic and international sales. The domestic demand for, and prices of, our coal primarily depend on coal consumption patterns of the domestic electric utility industry and the domestic steel industry. Consumption by the domestic electric utility industry is affected by the demand for electricity, environmental and other governmental regulations, technological developments and the price of competing coal and alternative fuel sources, such as natural gas, nuclear, hydroelectric, solar and wind power and other renewable energy sources. Consumption by the domestic steel industry is primarily affected by economic growth and the demand for steel used in construction as well as appliances and automobiles. The competitive environment for coal is impacted by a number of the largest markets in the world, including the United States, China, Japan and India, where demand for both electricity and steel has supported prices for steam and metallurgical coal. The economic stability of these markets has a significant effect on the demand for coal and the level of competition in supplying these markets. The cost of ocean transportation and the value of the U.S. dollar in relation to foreign currencies significantly impact the relative attractiveness of our coal as we compete on price with foreign coal producing sources. During the last several years, the U.S. coal industry has experienced increased consolidation, which has contributed to the industry becoming more competitive. Increased competition by coal producers or producers of alternate fuels could decrease the demand for, or pricing of, or both, for our coal, adversely impacting our results of operations and cash available for distribution.

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 Portions of our coal reserves possess quality characteristics that enable us to mine, process and market them as either metallurgical coal or high quality steam coal, depending on prevailing market conditions. A decline in the metallurgical market relative to the steam market could cause us to shift coal from the metallurgical market to the steam market, potentially reducing the price we could obtain for this coal and adversely impacting our cash flows, results of operations and cash available for distribution.

Any change in consumption patterns by utilities away from the use of coal, such as resulting from current low natural gas prices, could affect our ability to sell the coal we produce, which could adversely affect our results of operations and cash available for distribution to our unitholders.

Steam coal accounted for approximately 95%81% of our coal sales volume for the year ended December 31, 2015.2018. The majority of our sales of steam coal during this period were to electric utilities for use primarily as fuel for domestic electricity consumption. The amount of coal consumed by the domestic electric utility industry is affected primarily by the overall demand for electricity, environmental and other governmental regulations, and the price and availability of competing fuels for power plants such as nuclear, natural gas and oil as well as alternative sources of energy. We compete generally with producers of other fuels, such as natural gas and oil. A decline in price for these fuels could cause demand for coal to decrease and adversely affect the price of our coal. For example, sustained low natural gas prices have led, in some instances, to decreased coal consumption by electricity-generating utilities. If alternative energy sources, such as nuclear, hydroelectric, wind or solar, become more cost-competitive on an overall basis, demand for coal could decrease and the price of coal could be materially and adversely affected. Further, legislation requiring, subsidizing or providing tax benefitbenefits for the use of alternative energy sources and fuels, or legislation providing financing or incentives to encourage continuing technological advances in this area, could further enable alternative energy sources to become more competitive with coal. A decrease in coal consumption by the domestic electric utility industry could adversely affect the price of coal, which could materially adversely affect our results of operations and cash available for distribution to our unitholders.

Numerous political and regulatory authorities, along with environmental activist groups, are devoting substantial resources to anti-coal activities to minimize or eliminate the use of coal as a source of electricity generation, domestically and internationally, thereby further reducing the demand and pricing for coal, and potentially materially and adversely impacting our future financial results, liquidity and growth prospects.

Concerns about the environmental impacts of coal combustion, including perceived impacts on global climate issues, are resulting in increased regulation of coal combustion in many jurisdictions, unfavorable lending policies by government-backed lending institutions and development banks toward the financing of new overseas coal-fueled power plants and divestment efforts affecting the investment community, which could significantly affect demand for our products or our securities. Global climate issues continue to attract public and scientific attention. Numerous reports, such as the Fourth and Fifth Assessment Report of the Intergovernmental Panel on Climate Change, have also engendered concern about the impacts of human activity, especially fossil fuel combustion, on global climate issues. In turn, increasing government attention is being paid to global climate issues and to emissions of GHGs, including emissions of carbon dioxide from coal combustion by power plants. The 2015 Paris climate summit agreement resulted in voluntary commitments by numerous countries to reduce their GHG emissions, and could result in additional firm commitments by various nations with respect to future GHG emissions. These commitments could further disfavor coal-fired generation, particularly in the medium- to long-term.

Enactment of laws or passage of regulations regarding emissions from the combustion of coal by the United States, some of its states or other countries, or other actions to limit such emissions, could also result in electricity generators further switching from coal to other fuel sources or additional coal-fueled power plant closures. Further, policies limiting available financing for the development of new coal-fueled power plants could adversely impact the global demand for coal in the future.

There have also been efforts in recent years affecting the investment community, including investment advisors, sovereign wealth funds, public pension funds, universities and other groups, promoting the divestment of fossil fuel equities and also pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. In California, for example, legislation was signed into law in October 2015 that requires California’s state pension funds to divest investments in companies that generate 50% or more of their revenue from coal mining by July 2017. More recently, in December 2017, the Governor of New York announced that the New York Common Fund will immediately cease all new investments in entities with “significant fossil fuel activities,” and the World Bank announced that it will no longer finance upstream oil and gas after 2019, except in “exceptional circumstances.” Other activist campaigns have urged banks to cease financing coal-driven businesses. As a result, numerous major banks have enacted such policies. The impact of such efforts may adversely affect the demand for and price of securities issued by us, and impact our access to the capital and financial markets.

In addition, several well-funded non-governmental organizations have explicitly undertaken campaigns to minimize or eliminate the use of coal as a source of electricity generation. For example, the goals of Sierra Club’s “Beyond Coal” campaign include retiring one-third of the nation’s coal-fired power plants by 2020, replacing retired coal plants with “clean energy solutions,” and “keeping coal in the ground.”

The net effect of these developments is to make it more costly and difficult to maintain our business and to continue to depress demand and pricing for our coal. A substantial or extended decline in the prices we receive for our coal due to these or other factors could further reduce our revenue and profitability, cash flows, liquidity, and value of our coal reserves and result in losses.

Our mining operations are subject to extensive and costly environmental laws and regulations, and such current and future laws and regulations could materially increase our operating costs or limit our ability to produce and sell coal.

The coal mining industry is subject to numerous and extensive federal, state and local environmental laws and regulations, including laws and regulations pertaining to permitting and licensing requirements, air quality standards, plant and wildlife protection, reclamation and restoration of mining properties, the discharge of materials into the environment, the storage, treatment and disposal of wastes, protection of wetlands, surface subsidence from underground mining and the effects that mining has on groundwater quality and availability. The costs, liabilities and requirements associated with these laws and regulations are significant and time-consuming and may delay commencement or continuation of our operations. Moreover, the possibility exists that new laws or regulations (or new judicial interpretations or enforcement policies of existing laws and regulations) could materially affect our mining operations, results of operations and cash available for distribution to our unitholders, either through direct impacts such as those regulating our existing mining operations, or indirect impacts such as those that discourage or limit our customers'customers’ use of coal. Violations of applicable laws and regulations would subject us to administrative, civil and criminal penalties and a range of other possible sanctions. The enforcement of laws and regulations governing the coal mining industry has increased substantially. As a result, the consequences for any noncompliance may become more significant in the future.

Our operations use petroleum products, coal processing chemicals and other materials that may be considered "hazardous materials"“hazardous materials” under applicable environmental laws and have the potential to

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generate other materials, all of which may affect runoff or drainage water. In the event of environmental contamination or a release of these materials, we could become subject to claims for toxic torts, natural resource damages and other damages and for the investigation and cleanup of soil, surface water, groundwater, and other media, as well as abandoned and closed mines located on property we operate. Such claims may arise out of conditions at sites that we currently own or operate, as well as at sites that we previously owned or operated, or may acquire.

The government extensively regulates mining operations, especially with respect to mine safety and health, which imposes significant actual and potential costs on us, and future regulation could increase those costs or limit our ability to produce coal.

Coal mining is subject to inherent risks to safety and health. As a result, the coal mining industry is subject to stringent safety and health standards. Fatal mining accidents in the United States in recent years have received national attention and have led to responses at the state and federal levels that have resulted in increased regulatory scrutiny of coal mining operations, particularly underground mining operations. More stringent state and federal mine safety laws and regulations have included increased sanctions for non-compliance. Moreover, future workplace accidents are likely to result in more stringent enforcement and possibly the passage of new laws and regulations.

Within the last few years, the industry has seen enactment of the Federal Mine Improvement and New Emergency Response Act of 2006 (the "MINER Act"“MINER Act”), subsequent additional legislation and regulation imposing significant new safety initiatives and the Dodd-Frank Act, which, among other things, imposes new mine safety information reporting requirements. The MINER Act significantly amended the Federal Mine Safety and Health Act of 1977 (the "Mine Act"“Mine Act”), imposing more extensive and stringent compliance standards, increasing criminal penalties and establishing a maximum civil penalty for non-compliance, and expanding the scope of federal oversight, inspection, and enforcement activities. Following the passage of the MINER Act, the U.S. Mine Safety and Health Administration ("MSHA"(“MSHA”) issued new or more stringent rules and policies on a variety of topics, including:

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sealing off abandoned areas of underground coal mines;



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mine safety equipment, training and emergency reporting requirements;



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substantially increased civil penalties for regulatory violations;



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training and availability of mine rescue teams;



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underground "refuge alternatives" capable of sustaining trapped miners in the event of an emergency;



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flame-resistant conveyor belt, fire prevention and detection, and use of air from the belt entry; and



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post-accident two-way communications and electronic tracking systems.

For example, in 2014, MSHA adopted a final rule that reduces the permissible concentration of respirable dust in underground coal mines from the current standard of 2.0 milligrams per cubic meter of air to 1.5 milligram per cubic meter. The rule hashad a phased implementation schedule, and the third and final phase required to be implemented byof the rule became effective in August 2016. Under the phased approach, operators will bewere required to adopt new measures and procedures for dust sampling, record keeping, and medical surveillance. More recently,Additionally, in September 2015, MSHA issued a proposed rule requiring the installation ofthat would require underground coal mine operators to equip coal hauling machines and scoops on working sections with proximity detection systems on underground coal hauling systems used on the mining section.systems. Proximity detection is a technology that uses electronic sensors to detect motion and the distance between a miner and a machine. These systems provide audible and visual warnings, and automatically stop moving machines when miners are in the machines'machines’ path. These and other new safety rules could result in increased compliance costs on our operations. Subsequent to passage of the MINER Act, various coal producing

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states, including West Virginia, Ohio and Kentucky, have enacted legislation addressing issues such as mine safety and accident reporting, increased civil and criminal penalties, and increased inspections and oversight. Other states may pass similar legislation in the future. Additional federal and state legislation that would further increase mine safety regulation, inspection and enforcement, particularly with respect to underground mining operations, has also been considered.

Although we are unable to quantify the full impact, implementing and complying with these new laws and regulations could have an adverse impact on our results of operations and cash available for distribution to our unitholders and could result in harsher sanctions in the event of any violations. Please read "Part“Part 1, Item 1. Business—Regulation and Laws."”

Penalties, fines or sanctions levied by MSHA could have a material adverse effect on our business, results of operations and cash available for distribution.

Surface and underground mines like ours and those of our competitors are continuously inspected by MSHA, which often leads to notices of violation. Recently, MSHA has been conducting more frequent and more comprehensive inspections. In addition, in July 2014, MSHA proposed a rule that revises its civil penalty assessment provisions and how regulators should approach calculating penalties, which, in some instances, could resultedresult in increased civil penalty assessments for medium and larger mine operators and contractors by 300300% to 1,000 percent.1,000%. MSHA issued a revised proposed rule in February 2015, but, to date, has not taken any further action. However, increased scrutiny by MSHA and enforcement against mining operations are likely to continue.

 On June 24, 2011, our subsidiary, CAM Mining LLC received notice that on June 23, 2011, MSHA commenced an action

We have in the U.S. District Court ofpast, and may in the Eastern District of Kentucky seeking injunctive relief as a result offuture, be subject to fines, penalties or sanctions resulting from alleged violations of Sections 103, 104, and 108 of the Mine Act occurring at Mine 28 in connection with an inspection on June 17, 2011 by MSHA inspectors. The complaint alleged that when MSHA inspectors arrived at Mine 28 to inspect the mine with respect to the allegations that employees had been smoking underground, CAM Mining LLC employees gave advance notice of the inspection to miners working underground and that this advance notice hindered, interfered with and delayed the inspection by MSHA. The complaint asserts that the MSHA inspectors did not find any evidence of smoking paraphernalia during the inspection, which was allegedly the result of this advance notice. On June 30, 2011, MSHA obtained a temporary restraining order prohibiting any advance notice of inspections in the future. That became a Permanent Injunction on July 14, 2011. The Permanent Injunction is for three years and expired on July 14, 2014. On June 17, 2011, MSHA also issued a 104(a) citation in this matter to the Mine for allegedly giving advance notice of the inspection. The citation was assessed at $10,000 and was settled for $8,000 in 2014 upon approval by the administrative law judge.

        As a result of these and future inspections and alleged violations and potential violations, we could be subject to material fines, penalties or sanctions.regulations. Any of our mines could be subject to a temporary or extended shut down as a result of an alleged MSHA violation. Any suchfuture penalties, fines or sanctions could have a material adverse effect on our business, results of operations and cash available for distribution.

We may be unable to obtain and/or renew permits necessary for our operations, which could prevent us from mining certain reserves.

Numerous governmental permits and approvals are required for mining operations, and we can face delays, challenges to, and difficulties in acquiring, maintaining or renewing necessary permits and approvals, including environmental permits. The permitting rules, and the interpretations of these rules, are complex, change frequently, and are often subject to discretionary interpretations by regulators, all of which may make compliance more difficult or impractical, and may possibly preclude the

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continuance of ongoing mining operations or the development of future mining operations. In addition, the public has certain statutory rights to comment upon and otherwise impact the permitting process, including through court intervention. Over the past few years, the length of time needed to bring a new surface mine into production has increased because of the increased time required to obtain necessary permits. The slowing pace at which permits are issued or renewed for new and existing mines has materially impacted production in Appalachia, but could also affect other regions in the future.

Section 402 National Pollutant Discharge Elimination System permits and Section 404 CWA permits are required to discharge wastewater and discharge dredged or fill material into waters of the United States.States (“WOTUS”). Expansion of EPA jurisdiction over these areas has the potential to adversely impact our operations. For example,Considerable legal uncertainty exists surrounding the EPA releasedstandard for what constitutes jurisdictional waters and wetlands subject to the protections and requirements of the Clean Water Act. Please read “Part I, Item 1. Business—Regulation and Laws—Clean Water Act.” Currently, 26 states are subject to the 2015 rule, while the pre-2015 regulations and guidance continue to apply in 24 states. Should the 2015 rule be enforced in the states in which we operate, or should a finaldifferent rule in May 2015 that attempted to clarify federal jurisdiction underexpanding the CWA over watersdefinition of what constitutes a water of the United States butbe finalized as a numberresult of legal challenges to this rule are pending,EPA and implementation of the rule has been stayed nationwide. To the extent the rule expands the scope of the CWA's jurisdiction,Corps’s rulemaking process, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. Our surface coal mining operations typically require such permits to authorize such activities as the creation of slurry ponds, stream impoundments, and valley fills. Although the CWA gives the EPA a limited oversight role in the Section 404 permitting program, the EPA has recently asserted its authorities more forcefully to question, delay, and prevent issuance of some Section 404 permits for surface coal mining in Appalachia. Currently, significant uncertainty exists regarding the obtaining of permits under the CWA for coal mining operations in Appalachia due to various initiatives launched by the EPA regarding these permits.

Our mining operations are subject to operating risks that could adversely affect production levels and operating costs.

Our mining operations are subject to conditions and events beyond our control that could disrupt operations, resulting in decreased production levels and increased costs.

These risks include:

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unfavorable geologic conditions, such as the thickness of the coal deposits and the amount of rock embedded in or overlying the coal deposit;



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inability to acquire or maintain necessary permits or mining or surface rights;



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changes in governmental regulation of the mining industry or the electric utility industry;



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adverse weather conditions and natural disasters;



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accidental mine water flooding;



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labor-related interruptions;



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transportation delays;



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mining and processing equipment unavailability and failures and unexpected maintenance problems; and



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accidents, including fire and explosions from methane.

Any of these conditions may increase the cost of mining and delay or halt production at particular mines for varying lengths of time, which in turn could adversely affect our results of operations and cash available for distribution to our unitholders.

In general, mining accidents present a risk of various potential liabilities depending on the nature of the accident, the location, the proximity of employees or other persons to the accident scene and a range of other factors. Possible liabilities arising from a mining accident include workmen's

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workmen’s compensation claims or civil lawsuits for workplace injuries, claims for personal injury or property damage by people living or working nearby and fines and penalties including possible criminal enforcement against us and certain of our employees. In addition, a significant accident that results in a mine shut-down could give rise to liabilities for failure to meet the requirements of coal supply agreements especially if the counterparties dispute our invocation of the force majeure provisions of those agreements. We maintain insurance coverage to mitigate the risks of certain of these liabilities, including business interruption insurance, but those policies are subject to various exclusions and limitations and we cannot assure you that we will receive coverage under those policies for any personal injury, property damage or business interruption claims that may arise out of such an accident. Moreover, certain potential liabilities such as fines and penalties are not insurable risks. Thus, a serious mine accident may result in material liabilities that adversely affect our results of operations and cash available for distribution.

Fluctuations in transportation costs or disruptions in transportation services could increase competition or impair our ability to supply coal to our customers, which could adversely affect our results of operations and cash available for distribution to our unitholders.

Transportation costs represent a significant portion of the total cost of coal for our customers and, as a result, the cost of transportation is a critical factor in a customer'scustomer’s purchasing decision. Increases in transportation costs could make coal a less competitive energy source or could make our coal production less competitive than coal produced from other sources.

Significant decreases in transportation costs could result in increased competition from coal producers in other regions. For instance, coordination of the many eastern U.S. coal loading facilities, the large number of small shipments, the steeper average grades of the terrain and a more unionized workforce are all issues that combine to make shipments originating in the eastern United States inherently more expensive on a per-mile basis than shipments originating in the western United States. Historically, high coal transportation rates from the western coal producing regions limited the use of western coal in certain eastern markets. The increased competition could have an adverse effect on our results of operations and cash available for distribution to our unitholders.

We depend primarily upon railroads, barges and trucks to deliver coal to our customers. Disruption of any of these services due to weather-related problems, strikes, lockouts, accidents, mechanical difficulties and other events could temporarily impair our ability to supply coal to our customers, which could adversely affect our results of operations and cash available for distribution to our unitholders.

In recent years, the states of Kentucky and West Virginia have increased enforcement of weight limits on coal trucks on their public roads. It is possible that other states may modify their laws to limit truck weight limits. Such legislation and enforcement efforts could result in shipment delays and increased costs. An increase in transportation costs could have an adverse effect on our ability to increase or to maintain production and could adversely affect our results of operations and cash available for distribution.

A shortage of skilled labor in the mining industry could reduce productivity and increase operating costs, which could adversely affect our results of operations and cash available for distribution to our unitholders.

Efficient coal mining using modern techniques and equipment requires skilled laborers. During periods of high demand for coal, the coal industry has experienced a shortage of skilled labor as well as rising labor and benefit costs, due in large part to demographic changes as existing miners retire at a faster rate than new miners are entering the workforce. If a shortage of experienced labor should occur or coal producers are unable to train enough skilled laborers, there could be an adverse impact on labor productivity, an increase in our costs and our ability to expand production may be limited. If coal

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prices decrease or our labor prices increase, our results of operations and cash available for distribution to our unitholders could be adversely affected.

Unexpected increases in raw material costs, such as steel, diesel fuel and explosives could adversely affect our results of operations.

Our coal mining operations are affected by commodity prices. We use significant amounts of steel, diesel fuel, explosives and other raw materials in our mining operations, and volatility in the prices for these raw materials could have a material adverse effect on our operations. Steel prices and the prices of scrap steel, natural gas and coking coal consumed in the production of iron and steel fluctuate significantly and may change unexpectedly. Additionally, a limited number of suppliers exist for explosives, and any of these suppliers may divert their products to other industries. Shortages in raw materials used in the manufacturing of explosives, which, in some cases, do not have ready substitutes, or the cancellation of supply contracts under which these raw materials are obtained, could increase the prices and limit the ability of us or our contractors to obtain these supplies. Future volatility in the price of steel, diesel fuel, explosives or other raw materials will impact our operating expenses and could adversely affect our results of operations and cash available for distribution.

If we are not able to acquire replacement coal reserves that are economically recoverable, our results of operations and cash available for distribution to our unitholders could be adversely affected.

Our results of operations and cash available for distribution to our unitholders depend substantially on obtaining coal reserves that have geological characteristics that enable them to be mined at competitive costs and to meet the coal quality needed by our customers. Because we deplete our reserves as we mine coal, our future success and growth will depend, in part, upon our ability to acquire additional coal reserves that are economically recoverable. If we fail to acquire or develop additional reserves, our existing reserves will eventually be depleted. Replacement reserves may not be available when required or, if available, may not be capable of being mined at costs comparable to those characteristic of the depleting mines. We may not be able to accurately assess the geological characteristics of any reserves that we acquire, which may adversely affect our results of operations and cash available for distribution to our unitholders. Exhaustion of reserves at particular mines with certain valuable coal characteristics also may have an adverse effect on our operating results that is disproportionate to the percentage of overall production represented by such mines. Our ability to obtain other reserves in the future could be limited by restrictions under our existing or future debt agreements, competition from other coal companies for attractive properties, the lack of suitable acquisition candidates or the inability to acquire coal properties on commercially reasonable terms.

Inaccuracies in our estimates of coal reserves and non-reserve coal deposits could result in lower than expected revenues and higher than expected costs.

We base our coal reserve and non-reserve coal deposit estimates on engineering, economic and geological data assembled and analyzed by our staff, which is periodically audited by independent engineering firms. These estimates are also based on the expected cost of production and projected sale prices and assumptions concerning the permitability and advances in mining technology. The estimates of coal reserves and non-reserve coal deposits as to both quantity and quality are periodically updated to reflect the production of coal from the reserves, updated geologic models and mining recovery data, recently acquired coal reserves and estimated costs of production and sales prices. There are numerous factors and assumptions inherent in estimating quantities and qualities of coal reserves and non-reserve coal deposits and costs to mine recoverable reserves, including many factors beyond our control. Estimates of economically recoverable coal reserves necessarily depend upon a number of variable

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factors and assumptions, all of which may vary considerably from actual results. These factors and assumptions relate to:

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quality of coal;



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geological and mining conditions and/or effects from prior mining that may not be fully identified by available exploration data or which may differ from our experience in areas where we currently mine;



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the percentage of coal in the ground ultimately recoverable;



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the assumed effects of regulation, including the issuance of required permits, taxes, including severance and excise taxes and royalties, and other payments to governmental agencies;



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historical production from the area compared with production from other similar producing areas;



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the timing for the development of reserves; and



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assumptions concerning equipment and productivity, future coal prices, operating costs, capital expenditures and development and reclamation costs.

For these reasons, estimates of the quantities and qualities of the economically recoverable coal attributable to any particular group of properties, classifications of coal reserves and non-reserve coal deposits based on risk of recovery, estimated cost of production and estimates of net cash flows expected from particular reserves as prepared by different engineers or by the same engineers at different times may vary materially due to changes in the above factors and assumptions. Actual production from identified coal reserve and non-reserve coal deposit areas or properties and revenues and expenditures associated with our mining operations may vary materially from estimates. Accordingly, these estimates may not reflect our actual coal reserves or non-reserve coal deposits. Any inaccuracy in our estimates related to our coal reserves and non-reserve coal deposits could result in lower than expected revenues and higher than expected costs, which could have a material adverse effect on our ability to make cash distributions.

We invest in non-coal natural resource assets, which could result in a material adverse effect on our results of operations and cash available for distribution to our unitholders.

        Part of our business strategy is to expand our operations through strategic acquisitions, which includes investing in non-coal natural resources assets. Our executive officers do not have experience investing in or operating non-coal natural resources assets and we may be unable to hire additional management with relevant expertise in operating such assets. Acquisitions of non-coal natural resource assets could expose us to new and additional operating and regulatory risks, including commodity price risk, which could result in a material adverse effect on our results of operations and cash available for distribution to our unitholders.

The amount of estimated maintenance capital expenditures our general partner is required to deduct from operating surplus each quarter could increase in the future, resulting in a decrease in available cash from operating surplus that could be distributed to our unitholders.

Our partnership agreement requires our general partner to deduct from operating surplus each quarter estimated maintenance capital expenditures as opposed to actual maintenance capital expenditures in order to reduce disparities in operating surplus caused by fluctuating maintenance capital expenditures, such as reserve replacement costs or refurbishment or replacement of mine equipment. Our annual estimated maintenance capital expenditures for purposes of calculating operating surplus is based on our estimates of the amounts of expenditures we will be required to make in the future to maintain our long-term operating capacity. Our partnership agreement does not cap

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the amount of maintenance capital expenditures that our general partner may estimate. The amount of our estimated maintenance capital expenditures may be more than our actual maintenance capital expenditures, which will reduce the amount of available cash from operating surplus that we would otherwise have available for distribution to unitholders. The amount of estimated maintenance capital expenditures deducted from operating surplus is subject to review and change by the board of directors of our general partner at least once a year, with any change approved by the conflicts committee. In addition to estimated maintenance capital expenditures, reimbursement of expenses incurred by our general partner and its affiliates will reduce the amount of available cash from operating surplus that we would otherwise have available for distribution to our unitholders. Please read "—“—Risks Inherent in an Investment in Us—Cost reimbursements due to our general partner and its affiliates for services provided to us or on our behalf will reduce cash available for distribution to our unitholders. The amount and timing of such reimbursements will be determined by our general partner."”

Existing and future laws and regulations regulating the emission of sulfur dioxide and other compounds could affect coal consumers and as a result reduce the demand for our coal. A reduction in demand for our coal could adversely affect our results of operations and cash available for distribution to our unitholders.

Federal, state and local laws and regulations extensively regulate the amount of sulfur dioxide, particulate matter, nitrogen oxides, mercury and other compounds emitted into the air from electric power plants and other consumers of our coal. These laws and regulations can require significant emission control expenditures, and various new and proposed laws and regulations may require further emission reductions and associated emission control expenditures. A certain portion of our coal has a medium to high sulfur content, which results in increased sulfur dioxide emissions when combusted and therefore the use of our coal imposes certain additional costs on customers. Accordingly, these laws and regulations may affect demand and prices for our higher sulfur coal. Please read "Part“Part I, Item 1. Business—Regulation and Laws."”

Federal and state laws restricting the emissions of greenhouse gases in areas where we conduct our business or sell our coal could adversely affect our operations and demand for our coal.

One by-product of burning coal is carbon dioxide,CO₂, which EPA considers a GHG, and a major source of concern with respect to climate change and global warming. Global warming has garnered significant public attention, and measures have been implemented or proposed at the international, federal, state and regional levels to limit GHG emissions. Please read “Part I, Item 1. Business—Regulation and Laws—Climate Change.”

 Future regulation of GHG in the United States could occur pursuant to future U.S. treaty commitments, new domestic legislation that may impose a carbon emissions tax or establish a cap-and-trade program or regulation by the EPA.

For example, on the international level, the United States iswas one of almost 200 nations that agreed on December 12, 2015 to an international climate change agreement in Paris, France, that calls for countries to set their own GHG emission targets and be transparent about the measures each country will use to achieve its GHG emission targets; however, the agreement does not set binding GHG emission reduction targets. The Paris climate agreement entered into force in November 2016; however, in August 2017 the U.S. State Department officially informed the United Nations of the intent of the U.S. to withdraw from the agreement, with the earliest possible effective date of withdrawal being November 4, 2020. Despite the planned withdrawal, certain U.S. city and state governments have announced their intention to satisfy their proportionate obligations under the Paris Agreement. These commitments could further reduce demand and prices for coal.

        In August 2015,At the federal level, EPA has finalized a number of rules related to GHG emissions. For example, the EPA issued its final Clean Power Plan (the "CPP"),CPP rules that establish carbon pollution standards for power plants, called CO₂ emission performance rates. The EPA expects each state to develop implementation plans for power plants in its state to meet the individual state targets established in the CPP. The EPA has given states the option to develop compliance plans for annual rate-based reductions (pounds per megawatt hour) or mass-based tonnage limits for CO₂. The state plans are due in September 2016, subject to potential extensions of up to two years for final plan submission. The compliance period begins in 2022, and emission reductions will be phased in up to 2030. The EPA also proposed a federal compliance plan to implement the CPP in the event that an approvable state plan is not submitted to the EPA. Judicial challenges have been filed. On February 9, 2016,led the U.S. Supreme Court grantedto grant a stay of the implementation of the CPP before the United States Court of Appeals for the District of Columbia ("Circuit Court") even issued a decision.in February 2016. By its terms, this stay will remain in effect throughout the pendency of the appeals process including at the

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Circuit Court and the Supreme Court through any certiorari petition that may be granted.process. The stay suspends the rule, including the requirement that states submit their initial plans by September 2016. The Supreme Court'sCourt’s stay applies only to EPA'sEPA’s regulations for CO₂ emissions from existing power plants and will not affect EPA'sEPA’s standards for new power plants. It is not yet clear how the either the Circuit Court or the Supreme Courtcourts will rule on the legality of the CPP. Additionally, in October 2017 EPA proposed to repeal the CPP, although the final outcome of this action and the pending litigation regarding the CPP is uncertain at this time. In connection with the proposed repeal, EPA issued an Advance Notice of Proposed Rulemaking (“ANPRM”) in December 2017 regarding emission guidelines to limit GHG emissions from existing electricity utility generating units. In August 2018, the EPA issued the proposed ACE Rule, which would replace the CPP. If the ACE Rule is finalized, it will likely be subject to judicial challenge. If the effort to repeal and replace the CPP is unsuccessful and the rules were upheld at the conclusion of thisthe appellate process and were implemented in their current form, or if the ACE Rule results in state plans to reduce the level of GHG emissions from electric utility generating units, demand for coal will likely be further decreased. The EPA also issued a final rule for new coal-fired power plants in August 2015, which essentially set performance standards for coal-fired power plants that requires partial carbon capture and sequestration. Additional legal challenges have been filed against the EPA'sEPA’s rules for new power plants. The EPA'sEPA’s GHG rules for new and existing power plants, taken together, have the potential to severely reduce demand for coal. In addition, passage of any comprehensive federal climate change and energy legislation could impact the demand for coal. Any reduction in the amount of coal consumed by North American electric power generators could reduce the price of coal that we mine and sell, thereby reducing our revenues and materially and adversely affecting our business and results of operations.

Many states and regions have adopted greenhouse gas initiatives and certain governmental bodies have or are considering the imposition of fees or taxes based on the emission of greenhouse gases by certain facilities, including coal-fired electric generating facilities. For example, in 2005, ten northeastern states entered into the Regional Greenhouse Gas Initiative agreement (the "RGGI"“RGGI”), calling for implementation of a cap and trade program aimed at reducing carbon dioxide emissions from power plants in the participating states. The members ofFollowing the RGGI have established in statute and/or regulation a carbon dioxide trading program. Auctions for carbon dioxide allowances under the program began in September 2008. Though New Jersey withdrew from RGGI in 2011, since its inception,model, several additional northeasternwestern states and Canadian provinces have joined as participants or observers.

        Following the RGGI model, five western states launched the Western Regional Climate Action Initiative to identify, evaluate and implement collective and cooperative methods of reducing greenhouse gases in the region to 15% below 2005 levels by 2020. These states were joined by two additional states and four Canadian provinces and became collectively known as the Western Climate Initiative Partners. However, in November 2011, six states withdrew, leaving California and the four Canadian provinces as members. At a January 12, 2012 stakeholder meeting, this group confirmed a commitment and timetable to create the largesta carbon market in North America and provide a model to guide future efforts to establish national approaches in both Canada and the U.S. to reduce GHG emissions.America. It is likely that these regional efforts will continue.

Many coal-fired plants have already closed or announced plans to close and proposed new construction projects have also come under additional scrutiny with respect to GHG emissions. There have been an increasing number of protests and challenges to the permitting of new coal-fired power plants by environmental organizations and state regulators fordue to concerns related to greenhouse gas emissions. Other state regulatory authorities have also rejected the construction of new coal-fueled power plants based on the uncertainty surrounding the potential costs associated with GHG emissions from these plants under future laws limiting the emissions of carbon dioxide.GHGs. In addition, several permits issued to new coal-fired power plants without limits on GHG emissions have been appealed to the EPA'sEPA’s Environmental Appeals Board. In addition, over 30 states have adopted mandatory "renewable“renewable portfolio standards,"” which require electric utilities to obtain a certain percentage of their electric generation portfolio from renewable resources by a certain date. These standards range generally from 10% to 30%, over time periods that generally extend from the present until between 2020 and 2030. Other states may adopt similar requirements, and federal legislation is a possibility in this area. To the extent these requirements affect our current and prospective customers; they may reduce the demand for coal-fired power, and may affect long-term demand for our coal.

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If mandatory restrictions on carbon dioxide emissions are imposed, the ability to capture and store large volumes of carbon dioxide emissions from coal-fired power plants may be a key mitigation technology to achieve emissions reductions while meeting projected energy demands. A number of recent legislative and regulatory initiatives to encourage the development and use of carbon capture and storageCCS technology have been proposed or enacted. On February 3, 2010, President Obama sentFor example, in October 2015, the EPA released a memorandum torule that established, for the heads of fourteen Executive Departments and Federal Agencies establishing an Interagency Task Force on Carbon Capture and Storage ("CCS"). The goal was to develop a comprehensive and coordinated Federal strategy to speed the commercial development and deployment of clean coal technologies. On August 12, 2010, the Task Force delivered a series of recommendations on overcoming the barriers to the widespread, cost-effective deployment of CCS within ten years. The report concludes that CCS can play an important role in domestic GHG emissions reductions while preserving the option of using abundant domestic fossil energy resources. The EPA also recently finalizedfirst time, new source performance standards under the federal Clean Air Act for GHG forCO₂ emissions from new coal and oil-firedfossil fuel-fired electric utility generating power plants, which requiresplants. The EPA has designated partial carbon capture and sequestration as the best system of emission reduction for newly constructed fossil fuel-fired steam generating units at power plants to comply.employ to meet the standard. However, widespread cost-effective deployment of CCS will occur only if the technology is commercially available at economically competitive prices and supportive national policy frameworks are in place.

In the meantime, the EPA and other regulators are using existing laws, including the federal Clean Air Act, to limit emissions of carbon dioxide and other GHGs from major sources, including coal-fired power plants that may require the use of "best“best available control technology"technology” or "BACT."“BACT.” As state permitting authorities continue to consider GHG control requirements as part of major source permitting BACT requirements, costs associated with new facility permitting and use of coal could increase substantially. A growing concern is the possibility that BACT will be determined to be the use of an alternative fuel to coal.

As a result of these current and proposed laws, regulations and trends, electricity generators may elect to switch to other fuels that generate less GHG emissions, possibly further reducing demand for our coal, which could adversely affect our results of operations and cash available for distribution to our unitholders. Please read "Part I, Item 1. Business—Regulation

Finally, some scientists have warned that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and Laws—Carbon Dioxide Emissions."severity of storms, droughts and floods and other climatic events. If these warnings are correct, and if any such effects were to occur in areas where we or our customers operate, they could have an adverse effect on our assets and operations.

Federal and state laws require bonds to secure our obligations to reclaim mined property. Our inability to acquire or failure to maintain, obtain or renew these surety bonds could have an adverse effect on our ability to produce coal, which could adversely affect our results of operations and cash available for distribution to our unitholders.

We are required under federal and state laws to place and maintain bonds to secure our obligations to repair and return property to its approximate original state after it has been mined (often referred to as "reclamation"“reclamation”) and to satisfy other miscellaneous obligations. Federal and state governments could increase bonding requirements in the future. In August 2016, the OSMRE issued a Policy Advisory discouraging state regulatory authorities from approving self-bonding arrangements. The Policy Advisory indicated that the OSMRE would begin more closely reviewing instances in which states accept self-bonds for mining operations. In the same month, the OSMRE also announced that it was beginning the rulemaking process to strengthen regulations on self-bonding. Certain business transactions, such as coal leases and other obligations, may also require bonding. We may have difficulty procuring or maintaining our surety bonds. Our bond issuers may demand higher fees, additional collateral, including supporting letters of credit or posting cash collateral or other terms less favorable to us upon those renewals. The failure to maintain or the inability to acquire sufficient surety bonds, as required by state and federal laws, could subject us to fines and penalties as well as the loss of our mining permits. Such failure could result from a variety of factors, including:

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the lack of availability, higher expense or unreasonable terms of new surety bonds;



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the ability of current and future surety bond issuers to increase required collateral; and



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the exercise by third-party surety bond holders of their right to refuse to renew the surety bonds.

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We maintain surety bonds with third parties for reclamation expenses and other miscellaneous obligations. It is possible that we may in the future have difficulty maintaining our surety bonds for mine reclamation. Due to adverse economic conditions and the volatility of the financial markets, surety bond providers may be less willing to provide us with surety bonds or maintain existing surety bonds or may demand terms that are less favorable to us than the terms we currently receive. We may have greater difficulty satisfying the liquidity requirements under our existing surety bond contracts. As of December 31, 2015,2018, we had $58.5$42.6 million in reclamation surety bonds, secured by $22.4$3.0 million in letterscash collateral held by our surety bond provider. Of the $42.6 million, approximately $0.4 million relates to surety bonds for Deane Mining, LLC and approximately $3.4 million relates to surety bonds for Sands Hill Mining, LLC, which in each case have not been transferred or replaced by the buyers of credit outstandingDeane Mining, LLC or Sands Hill Mining, LLC as was agreed to by the parties as part of the transactions.  We can provide no assurances that a surety company  will underwrite the surety bonds of the purchasers of these entities, nor are we aware of the actual amount of reclamation at any given time.  Further,if there was a claim under our credit agreement. Based onthese surety bonds prior to the March 2016 amendment, our credit agreement provides for a $80 million working capital revolving credit facility,transfer or replacement of which up to $30.0 million may be used for letterssuch bonds by the buyers of credit. If we do not maintain sufficient borrowing capacity under our revolving credit facility for additional letters of credit,Deane Mining, LLC or Sands Hill Mining, LLC, then we may be unableresponsible to obtainthe surety company for any amounts it pays in respect of such claim. While the buyers are required to indemnify us for damages, including reclamation liabilities, pursuant the agreements governing the sales of these entities, we may not be successful in obtaining any indemnity or renew surety bonds required for our mining operations.any amounts received may be inadequate. For more information, please read "Part II,“Part I, Item 7. Management's Discussion and Analysis1. Business— Recent Developments—Letter of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Agreement."Facility—PNC Bank.” If we do not maintain sufficient borrowing capacity or have other resources to satisfy our surety and bonding requirements, our operations and cash available for distribution to our unitholders could be adversely affected.

We depend on a few customers for a significant portion of our revenues. If a substantial portion of our supply contracts terminate or if any of these customers were to significantly reduce their purchases of coal from us, and we are unable to successfully renegotiate or replace these contracts on comparable terms, then our results of operations and cash available for distribution to our unitholders could be adversely affected.

We sell a material portion of our coal under supply contracts. As of December 31, 2015,2018, we had sales commitments for approximately 92%74% of our estimated coal production (including purchased coal to supplement our production) for the year ending December 31, 2016.2019. When our current contracts with customers expire, our customers may decide not to extend or enter into new contracts. Of our total future committed tons, under the terms of the supply contracts, we will ship 60%61% in 2016, 35%2019, 33% in 2017,2020, and 5%6% in 2018.2021. We derived approximately 83.9%80.5% of our total coal revenues from coal sales to our ten largest customers for the year ended December 31, 2015,2018, with affiliates of our top three customers accounting for approximately 45.2%40.4% of our coal revenues during that period.

In the absence of long-term contracts, our customers may decide to purchase fewer tons of coal than in the past or on different terms, including different pricing terms. Negotiations to extend existing contracts or enter into new long-term contracts with those and other customers may not be successful, and those customers may not continue to purchase coal from us under long-term coal supply contracts or may significantly reduce their purchases of coal from us. In addition, interruption in the purchases by or operations of our principal customers could significantly affect our results of operations and cash available for distribution. Unscheduled maintenance outages at our customers'customers’ power plants and unseasonably moderate weather are examples of conditions that might cause our customers to reduce their purchases. Our mines may have difficulty identifying alternative purchasers of their coal if their existing customers suspend or terminate their purchases. For additional information relating to these contracts, please read "Part“Part I, Item 1. Business—Customers—Coal Supply Contracts."”

Certain provisions in our long-term coal supply contracts may provide limited protection during adverse economic conditions, may result in economic penalties to us or permit the customer to terminate the contract.

Price adjustment, "price re-opener"“price re-opener” and other similar provisions in our supply contracts may reduce the protection from short-term coal price volatility traditionally provided by such contracts. Price re-opener provisions typically require the parties to agree on a new price. Failure of the parties to agree on a price under a price re-opener provision can lead to termination of the contract. Any adjustment or renegotiations leading to a significantly lower contract price could adversely affect our results of operations and cash available for distribution to our unitholders.

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Coal supply contracts also typically contain force majeure provisions allowing temporary suspension of performance by us or our customers during the duration of specified events beyond the control of the affected party. Most of our coal supply contracts also contain provisions requiring us to deliver coal meeting quality thresholds for certain characteristics such as Btu, sulfur content, ash content, hardness and ash fusion temperature. Failure to meet these specifications could result in economic penalties, including price adjustments, the rejection of deliveries or termination of the contracts. In addition, certain of our coal supply contracts permit the customer to terminate the agreement in the event of changes in regulations affecting our industry that increase the price of coal beyond a specified limit.

Our coal lessees' mining operations and their financial condition and results of operations are subject to some of the same risks and uncertainties that we face as a mine operator.

        The mining operations and financial condition and results of operations of our coal lessees are subject to the same risks and uncertainties that we face as a mine operator. If any such risks were to occur, the business, financial condition and results of operations of the lessees could be adversely affected and as a result our coal royalty revenues and cash available for distribution could be adversely affected.

If our coal lessees do not manage their operations well, their production volumes and our royalty revenues could decrease.

        We depend on our coal lessees to effectively manage their operations on the leased properties. The lessees make their own business decisions with respect to their operations within the constraints of their leases, including decisions relating to:

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marketing of the coal mined;



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mine plans, including the amount to be mined and the method of mining;



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processing and blending coal;



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expansion plans and capital expenditures;



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credit risk of their customers;



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permitting;



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insurance and surety bonding;



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acquisition of surface rights and other coal estates;



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employee wages;



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transportation arrangements;



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compliance with applicable laws, including environmental laws; and



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mine closure and reclamation.

        A failure on the part of one of the coal lessees to make royalty payments could give us the right to terminate the lease, repossess the property and enforce payment obligations under the lease. If we repossessed any of our properties, we might not be able to find a replacement lessee or enter into a new lease on favorable terms within a reasonable period of time. In addition, the existing lessee could be subject to bankruptcy proceedings that could further delay the execution of a new lease or the assignment of the existing lease to another operator. If we enter into a new lease, the replacement operator might not achieve the same levels of production or sell coal at the same price as the lessee it replaced. In addition, it may be difficult to secure new or replacement lessees for small or isolated coal

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reserves, since industry trends toward consolidation favor larger-scale, higher-technology mining operations in order to increase productivity.

Coal lessees could satisfy obligations to their customers with coal from properties other than ours, depriving us of the ability to receive amounts in excess of minimum royalty payments.

        Coal supply contracts often require operators to satisfy their obligations to their customers with resources mined from specific reserves or may provide the operator flexibility to source the coal from various reserves. Several factors may influence a coal lessee's decision to supply its customers with coal mined from properties we do not own or lease, including the royalty rates under the coal lessee's lease with us, mining conditions, mine operating costs, cost and availability of transportation, and customer specifications. If a coal lessee satisfies its obligations to its customers with coal from properties we do not own or lease, production on our properties will decrease, and we will receive lower royalty revenues.

A coal lessee may incorrectly report royalty revenues, which might not be identified by our lessee audit process or our mine inspection process or, if identified, might be identified in a subsequent period.

        We depend on our lessees to correctly report production and royalty revenues on a monthly basis. Our regular lessee audits and mine inspections may not discover any irregularities in these reports or, if we do discover errors, we might not identify them in the reporting period in which they occurred. Any undiscovered reporting errors could result in a loss of royalty revenues and errors identified in subsequent periods could lead to accounting disputes as well as disputes with the coal lessees, or internal control deficiencies.

Defects in title in the coal properties that we own or loss of any leasehold interests could limit our ability to mine these properties or result in significant unanticipated costs.

We conduct a significant part of our mining operations on leased properties. A title defect or the loss of any lease could adversely affect our ability to mine the associated coal reserves. Title to most of our owned and leased properties and the associated mineral rights is not usually verified until we make a commitment to develop a property, which may not occur until after we have obtained necessary permits and completed exploration of the property. In some cases, we rely on title information or representations and warranties provided by our grantors or lessors, as the case may be. Our right to mine some coal reserves would be adversely affected by defects in title or boundaries or if a lease expires. Any challenge to our title or leasehold interest could delay the exploration and development of the property and could ultimately result in the loss of some or all of our interest in the property. Mining operations from time to time may rely on a lease that we are unable to renew on terms at least as favorable, if at all. In such event, we may have to close down or significantly alter the sequence of mining operations or incur additional costs to obtain or renew such leases, which could adversely affect our future coal production. If we mine on property that we do not control, we could incur liability for such mining.

Our work force could become unionized in the future, which could adversely affect our production and labor costs and increase the risk of work stoppages.

Currently, none of our employees are represented under collective bargaining agreements. However, all of our work force may not remain union-free in the future. If some or all of our work force were to become unionized, it could adversely affect our productivity and labor costs and increase the risk of work stoppages.

TableIf we sustain cyber-attacks or other security breaches that disrupt our operations, or that result in the unauthorized release of Contentsproprietary or confidential information, we could be exposed to significant liability, reputational harm, loss of revenue, increased costs or other risks.

We may be subject to security breaches which could result in unauthorized access to our facilities or to information we are trying to protect. Unauthorized physical access to one or more of our facilities or locations, or electronic access to our proprietary or confidential information could result in, among other things, unfavorable publicity, litigation by parties affected by such breach, disruptions to our operations, loss of customers, and financial obligations for damages related to the theft or misuse of such information, any of which could have a substantial impact on our results of operations, financial condition or cash flow.

We depend on key personnel for the success of our business.

We depend on the services of our senior management team and other key personnel, including senior management of our general partner. The loss of the services of any member of senior management or key employee could have an adverse effect on our business and reduce our ability to make distributions to our unitholders. We may not be able to locate or employ on acceptable terms qualified replacements for senior management or other key employees if their services were no longer available.

If the assumptions underlying our reclamation and mine closure obligations are materially inaccurate, we could be required to expend greater amounts than anticipated.

The Federal Surface Mining Control and Reclamation Act of 1977 and counterpart state laws and regulations establish operational, reclamation and closure standards for all aspects of surface mining as well as most aspects of underground mining. Estimates of our total reclamation and mine closing liabilities are based upon permit requirements and our engineering expertise related to these requirements. The estimate of ultimate reclamation liability is reviewed both periodically by our management and annually by independent third-party engineers. The estimated liability can change significantly if actual costs vary from assumptions or if governmental regulations change significantly. Please read "Part“Part II, Item 7. Management'sManagement’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates—Asset Retirement Obligations."”

Our debt levels may limit our flexibility in obtaining additional financing and in pursuing other business opportunities.

Our level of indebtedness could have important consequences to us, including the following:

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our ability to obtain additional financing, if necessary, for working capital, capital expenditures (including acquisitions) or other purposes may be impaired or such financing may not be available on favorable terms;



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covenants contained in our existing and future credit and debt arrangements will require us to meet financial tests that may affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities;



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we will need a portion of our cash flow to make principal and interest payments on our indebtedness, reducing the funds that would otherwise be available for operations, distributions to unitholders and future business opportunities;



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we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and



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our flexibility in responding to changing business and economic conditions may be limited.

Increases in our total indebtedness would increase our total interest expense, which would in turn reduce our forecasted cash available for distribution. As of December 31, 20152018 our current portion of long-term debt that will be funded from cash flows from operating activities during 20162019 was approximately $41.5$2.2 million. Our ability to service our indebtedness will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing our indebtedness, or seeking additional equity capital or bankruptcy protection. We may not be able to effectaffect any of these remedies on satisfactory terms, or at all.

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Our creditfinancing agreement contains operating and financial restrictions that may restrict our business and financing activities and limit our ability to pay distributions upon the occurrence of certain events.

The operating and financial restrictions and covenants in our creditfinancing agreement and any future financing agreements could restrict our ability to finance future operations or capital needs or to engage, expand or pursue our business activities. For example, our creditfinancing agreement restricts our ability to:

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incur additional indebtedness or guarantee other indebtedness;



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grant liens;



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make certain loans or investments;



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dispose of assets outside the ordinary course of business, including the issuance and sale of capital stock of our subsidiaries;



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change the line of business conducted by us or our subsidiaries;



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enter into a merger, consolidation or make acquisitions; or



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make distributions if an event of default occurs.

In addition, our payment of principal and interest on our debt will reduce cash available for distribution on our units. Our creditfinancing agreement limits our ability to pay distributions upon the occurrence of the following events, among others, which would apply to us and our subsidiaries:

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failure to pay principal, interest or any other amount when due;



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breach of the representations or warranties in the credit agreement;



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failure to comply with the covenants in the credit agreement;



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cross-default to other indebtedness;



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bankruptcy or insolvency;



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failure to have adequate resources to maintain, and obtain, operating permits as necessary to conduct our operations substantially as contemplated by the mining plans used in preparing the financial projections; and



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a change of control.

Any subsequent refinancing of our current debt or any new debt could have similar restrictions. Our ability to comply with the covenants and restrictions contained in our creditfinancing agreement may be affected by events beyond our control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If we violate any of the restrictions, covenants, ratios or tests in our credit agreement, a significant portion of our indebtedness may become immediately due and payable, and our lenders'lenders’ commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. In addition, our obligations under our credit agreement will be secured by substantially all of our assets, and if we are unable to repay our indebtedness under our creditfinancing agreement, the lenders could seek to foreclose on such assets. For more information, please read "Part II,“Part I, Item 7. Management's Discussion1. Business—Recent Developments—Financing Agreement.”

Our business is subject to cybersecurity risks.

As is typical of modern businesses, we are reliant on the continuous and Analysisuninterrupted operation of Financial Conditionits information technology (“IT”) systems. User access of our sites and ResultsIT systems can be critical elements to our operations, as is cloud security and protection against cyber security incidents. Any IT failure pertaining to availability, access or system security could potentially result in disruption of Operations—Liquidityour activities, and Capital Resources—Credit Agreement."could adversely affect our reputation, operations or financial performance.

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Potential risks to the our IT systems could include unauthorized attempts to extract business sensitive, confidential or personal information, denial of Contentsaccess extortion, corruption of information or disruption of business processes, or by inadvertent or intentional actions by the our employees or vendors. A cybersecurity incident resulting in a security breach or failure to identify a security threat could disrupt business and could result in the loss of sensitive, confidential information or other assets, as well as litigation, regulatory enforcement, violation of privacy or securities laws and regulations, and remediation costs, all of which could materially impact the our business or reputation.

Risks Inherent in an Investment in Us

Royal owns and controls our general partner. Our general partner has fiduciary duties to its owners, and the interests of its owners may differ significantly from, or conflict with, the interests of our public common unitholders.

Royal owns and controls our general partner. Please read "Part I, Item 1. Business—Recent Developments—Sale of our General Partner by Wexford." Although our general partner has a fiduciary duty to manage us in a manner beneficial to us and our unitholders, the executive officers and directors of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to its owners. Therefore, conflicts of interest may arise between its owners and our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of its owners over the interests of our common unitholders. These conflicts include the following situations:

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our general partner is allowed to take into account the interests of parties other than us, such as its owners, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders;



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



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our partnership agreement limits the liability of and reduces fiduciary duties owed by our general partner and also restricts the remedies available to unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty;



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



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



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our general partner determines the amount and timing of any capital expenditure and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus;



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our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination period;



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our partnership agreement permits us to distribute up to $25.0 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions on our subordinated units or the incentive distribution rights;



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



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



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



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

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



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



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

In addition, Royal, its owners and entities in which they have an interest may compete with us. Please read "—“—Our sponsor, Royal and affiliates of our general partner may compete with us."”

Common units held by unitholders who are not eligible citizens will be subject to redemption.

In order to comply with U.S. laws with respect to the ownership of interests in mineral leases on federal lands, we have adopted certain requirements regarding those investors who own our common units. As used in this report, an eligible citizen means a person or entity qualified to hold an interest in mineral leases on federal lands. As of the date hereof, an eligible citizen must be: (1) a citizen of the United States; (2) a corporation organized under the laws of the United States or of any state thereof; or (3) an association of U.S. citizens, such as a partnership or limited liability company, organized under the laws of the United States or of any state thereof, but only if such association does not have any direct or indirect foreign ownership, other than foreign ownership of stock in a parent corporation organized under the laws of the United States or of any state thereof. For the avoidance of doubt, onshore mineral leases or any direct or indirect interest therein may be acquired and held by aliens only through stock ownership, holding or control in a corporation organized under the laws of the United States or of any state thereof. Unitholders who are not persons or entities who meet the requirements to be an eligible citizen run the risk of having their units redeemed by us at the lower of their purchase price cost or the then-current market price. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner.

Our general partner intends to limit its liability regarding our obligations.

Our general partner intends to limit its liability under contractual arrangements so that the counterparties to such arrangements have recourse only against our assets, and not against our general partner or its assets. Our general partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our general partner. Our partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner'spartner’s fiduciary duties, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our general partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders.

Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.

We expect that we will distribute all of our available cash to our unitholders and will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. As a result, to the extent we are unable to finance growth externally; our cash distribution policy will significantly impair our ability to grow.

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In addition, because we distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitationsWe may, in certain circumstances, be permitted under our partnership agreement or ourand credit agreement on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may impact the available cash that we have to distribute to our unitholders.

Our partnership agreement limits our general partner'spartner’s fiduciary duties to holders of our common and subordinated units.

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

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how to allocate business opportunities among us and its affiliates;



•

whether to exercise its limited call right;



•

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



•

whether to exercise its registration rights;



•

whether to elect to reset target distribution levels; and



•

whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement.

By purchasing a common unit, a unitholder is treated as having consented to the provisions in the partnership agreement, including the provisions discussed above.

Our partnership agreement restricts the remedies available to holders of our common and subordinated units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement:

•

provides that whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is required to make such determination, or take or decline to take such other action, in good faith, and will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;



•

provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith, meaning that it believed that the decision was in the best interest of our partnership;

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provides that our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and



•

provides that our general partner will not be in breach of its obligations under the partnership agreement or its fiduciary duties to us or our limited partners if a transaction with an affiliate or the resolution of a conflict of interest is:



(1)

approved by the conflicts committee of the board of directors of our general partner, although our general partner is not obligated to seek such approval;



(2)

approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and its affiliates;



(3)

on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or



(4)

fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.

In connection with a situation involving a transaction with an affiliate or a conflict of interest, any determination by our general partner must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the conflicts committee and the board of directors of our general partner determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest satisfies either of the standards set forth in subclauses (3) and (4) above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

Our sponsor, Royal, and affiliates of our general partner may compete with us.

Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than acting as our general partner and those activities incidental to its ownership interest in us. However, affiliates of our general partner, including our sponsor, Royal, are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. In addition, Royal and its affiliates may compete with us for investment opportunities and may own an interest in entities that compete with us. Further, Royal and its affiliates may acquire, develop or dispose of additional coal properties or other assets in the future without any obligation to offer us the opportunity to purchase or develop any of those assets.

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

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

Our general partner has the right, at any time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (48.0%) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our distributions at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution will be adjusted to equal the reset minimum quarterly distribution and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.

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

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

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

Even if holders of our common units are dissatisfied, they cannot currently remove our general partner without its consent.

If our unitholders are dissatisfied with the performance of our general partner, they will have limited ability to remove our general partner. Unitholders are currently unable to remove our general partner without its consent because our general partner and its affiliates own sufficient units to be able to prevent its removal. The vote of the holders of at least 66²/₃% of all outstanding common and subordinated units voting together as a single class is required to remove our general partner. As of March 21, 2016,15, 2019, Royal owned an aggregate of approximately 85%52.9% of our common and subordinated units. Also, if our general partner is removed without cause during the subordination period and no

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units held by the holders of the subordinated units or their affiliates are voted in favor of that removal, all remaining subordinated units will automatically be converted into common units and any existing arrearages on the common units will be extinguished. Cause is narrowly defined in our partnership agreement to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our general partner liable for actual fraud or willful or wanton misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business.

Our general partner interest or the control of our general partner may be transferred to a third party without unitholder consent.

Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of our unitholders. Furthermore, our partnership agreement does not restrict the ability of the members of our general partner to transfer their respective membership interests in our general partner to a third party. The new members of our general partner would then be in a position to replace the board of directors and executive officers of our general partner with their own designees and thereby exert significant control over the decisions taken by the board of directors and executive officers of our general partner. This effectively permits a "change“change of control"control” without the vote or consent of the unitholders.

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

If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price equal to the greater of (1) the average of the daily closing price of the common units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed and (2) the highest per-unit price paid by our general partner or any of its affiliates for common units during the 90-day period preceding the date such notice is first mailed. As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return or a negative return on their investment. Unitholders may also incur a tax liability upon a sale of their units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the limited call right. There is no restriction in our partnership agreement that prevents our general partner from issuing additional common units and exercising its call right. If our general partner exercised its limited call right, the effect would be to take us private and, if the units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Securities Exchange Act of 1934 (the "Exchange Act"“Exchange Act”). As of March 21, 2016,15, 2019, Royal owned an aggregate of approximately 87%49.4% of our common units and approximately 77%93.2% of our subordinated units.

We may issue additional units without unitholder approval, which would dilute existing unitholder ownership interests.

Our partnership agreement does not limit the number of additional limited partner interests we may issue at any time without the approval of our unitholders. The issuance of additional common units, preferred units or other equity interests of equal or senior rank will have the following effects:

•

	●	our existing unitholders’ proportionate ownership interest in us will decrease;
	●	the amount of cash available for distribution on each unit may decrease;
	●	because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;
	●	the ratio of taxable income to distributions may increase;
	●	the relative voting strength of each previously outstanding unit may be diminished; and
	●	the market price of the common units may decline.

The Series A preferred units are senior in right of distributions and liquidation and upon conversion, would result in the issuance of additional common units in the future, which could result in substantial dilution of our existing unitholders' proportionatecommon unitholders’ ownership interestinterests.

The Series A preferred units are a new class of partnership interests that rank senior to our common units with respect to distribution rights and rights upon liquidation. We are required to pay annual distributions on the Series A preferred units in an amount equal to the greater of (i) 50% of CAM Mining free cash flow (which is defined in our partnership agreement as (i) the total revenue of the our Central Appalachia business segment, minus (ii) the cost of operations (exclusive of depreciation, depletion and amortization) for the our Central Appalachia business segment, minus (iii) an amount equal to $6.50, multiplied by the aggregate number of met coal and steam coal tons sold by us from our Central Appalachia business segment) and (ii) an amount equal to the number of outstanding Series A preferred units multiplied by $0.80. If we fail to pay the any or all of the distributions in respect of the Series A preferred units, such deficiency will decrease;



•

accrue until paid in full and we will not be permitted to pay any distributions on our partnership interests that rank junior to the Series A preferred units, including our common units. The preferred units also rank senior to the common units in right of liquidation, and will be entitled to receive a liquidation preference in any such case.

We may convert the Series A preferred units into common units at any time on or after the time at which the amount of cash available for distribution onaggregate distributions paid in respect of each Series A preferred unit may decrease;



•

because a lower percentage of total outstandingexceeds $10.00 per unit. All unconverted Series A preferred units will be subordinatedconvert into common units the risk that a shortfallon December 31, 2021. The number of common units issued in the payment of the minimum quarterly distributionany conversion will be borne by our common unitholders will increase;

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•

based on the ratio of taxable income to distributions may increase;



•

the relative voting strength of each previously outstanding unit may be diminished; and



•

the marketvolume-weighted average closing price of the common units may decline.

In addition, to the extent the preferred units are converted into more than 66 2/3% of our common units, the holders of the preferred will have the right to remove our general partner.

Holders of our Series A preferred units have substantial negative control rights.

For as long as the Series A preferred units are outstanding, we will be restricted from taking certain actions without the consent of the holders of a majority of the Series A preferred units, including: (i) the issuance of additional Series A preferred units, or securities that rank senior or equal to the Series A preferred units; (ii) the sale or transfer of CAM Mining, LLC or a material portion of its assets; (iii) the repurchase of common units, or the issuance of rights or warrants to holders of common units entitling them to purchase common units at less than fair market value; (iv) consummation of a spin off; (v) the incurrence, assumption or guaranty indebtedness for borrowed money in excess of $50.0 million except indebtedness relating to entities or assets that are acquired by the Partnership or its affiliates that is in existence at the time of such acquisition or (vi) the modification of CAM Mining’s accounting principles or the financial or operational reporting principles of the our Central Appalachia business segment, subject to certain exceptions. These consent rights effectively add a constituency to our fundamental decision-making process, and failure to obtain such consent from the Series A preferred holders could prevent us from taking an action that our management or board of directors otherwise view as prudent or necessary for our business operations or the execution of our business strategy.

The market price of our common units could be adversely affected by sales of substantial amounts of our common units in the public or private markets, including sales by Royal or other large holders.

As of March 21, 2016,15, 2019, we had 76,919,13713,098,353 common units, 1,143,686 subordinated units and 12,355,299 subordinated1,500,000 Series A preferred units outstanding. All of the subordinated units will convert into common units on a one-for-one basis at the end of the subordination period. On March 21, 2016, we issued 60,000,0006,000,000 common units to Royal in a private placement. In connection with this issuance, we entered into a registration rights agreement with Royal which grants Royal piggyback registration rights under certain circumstances with respect to these common units. In addition, under our partnership agreement, our general partner and its affiliates (including Royal) have registration rights relating to the offer and sale of any units that they hold, subject to certain limitations. Sales by Royal or other large holders of a substantial number of our common units in the public markets, or the perception that such sales might occur, could have a material adverse effect on the price of our common units or could impair our ability to obtain capital through an offering of equity securities.

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.

Our partnership agreement restricts unitholders'unitholders’ voting rights by providing that any units held by a person or group that owns 20% or more of any class of units then outstanding, other than our general partner and its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter.

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

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

While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including provisions requiring us to make cash distributions contained therein, may be amended.

While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including provisions requiring us to make cash distributions contained therein, may be amended. Our partnership agreement generally may not be amended during the subordination period without the approval of our public common unitholders. However, our partnership agreement can be amended with the consent of our general partner and the approval of a majority of the outstanding common units (including common units held by Royal) after the subordination period has ended. As of March 21, 2016,15, 2019, Royal owned approximately 87%49.4% of the outstanding common units and 77%93.2% of our outstanding subordinated units.

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Unitholders may have liability to repay distributions and in certain circumstances may be personally liable for our obligations.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act (the "Delaware Act"“Delaware Act”), we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. A purchaser of units who becomes a limited partner is liable for the obligations of the transferring limited partner to make contributions to the partnership that are known to the purchaser of units at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership agreement. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

It may be determined that the right, or the exercise of the right by the limited partners as a group, to (i) remove or replace our general partner, (ii) approve some amendments to our partnership agreement or (iii) take other action under our partnership agreement constitutes "participation“participation in the control"control” of our business. A limited partner that participates in the control of our business within the meaning of the Delaware Act may be held personally liable for our obligations under the laws of Delaware, to the same extent as our general partner. This liability would extend to persons who transact business with us under the reasonable belief that the limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of our general partner.

The NYSE does not require a publicly traded limited partnership to comply with certain of its corporate governance requirements.

        Assuming we are able to maintain the listing of our common units on the NYSE, as a publicly traded limited partnership, the NYSE does not require us to have a majority of independent directors on our general partner's board of directors or to establish a compensation committee or a nominating and corporate governance committee. Accordingly, unitholders will not have the same protections afforded to certain corporations that are subject to all of the NYSE corporate governance requirements. Please read "—Risks Inherent in Our Business—Our common units have been suspended from trading on the NYSE and may cease to be listed on the NYSE should we lose the appeal of the suspension and delisting of our common units. Furthermore, even if we were to successfully appeal the suspension and delisting of our common units from the NYSE, we may be unable to maintain compliance with the NYSE continued listing requirements."

Tax Risks to Common Unitholders

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If our partnership statusthe Internal Revenue Service (“IRS”) were to treat us as a corporation for U.S. federal income tax purposes, changes or we become subject to material additional amounts of entity-level taxation for state tax purposes, then the value ofour cash available for distribution to our common units mayunitholders would be substantially reduced.

 We are currently

The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for U.S. federal income tax purposes. A publicly tradedDespite the fact that we are organized as a limited partnership such as us isunder Delaware law, we will be treated as a partnership only if it satisfiescorporation for federal income tax purposes unless we satisfy a "qualifying income"“qualifying income” requirement. Based on our current operations and current Treasury Regulations, we believe that we satisfy the qualifying income requirement and will be treated as a partnership. We have received a favorable private letter ruling from the IRS to the effect that, based on facts presented in the private letter ruling request, income from management fees, cost reimbursements and cost-sharing payments related to our management and operation of mining, production, processing, and sale of coal and from energy infrastructure support services will constitute “qualifying income” within the meaning of Section 7704 of the Internal Revenue Code of 1986 (the “Code”). We may, however, decide that it is in our best interest to be treated as a corporation for U.S. federal income tax purposes. A failureFailing to meet the qualifying income requirement,

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a change in current law, or an election to be treated as a decision to elect corporate treatment,corporation, could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

If we were treated as a corporation for U.S. federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate which is currently a maximum of 35%, and would likely pay state and local income tax at varying rates. Any distributions to you would generally be taxed again as corporate distributions, and no income, gains, losses, deductions, or credits would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to our common unitholders would be substantially reduced. Therefore, treatment of us as a corporation may result inwould materially reduce the after-tax return to our common unitholders, likely causing a substantial reduction in the value of our common units.

Additionally, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise, or other forms of taxation. We currently own assets and conduct business in several states that impose a margin or franchise tax. In the future, we may expand our operations to other states. Imposition of a similar tax on us in jurisdictions to which we expand could substantially reduce our cash available for distribution to our common unitholders. Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to additional amounts of entity level taxation for U.S. federal, state, local, or stateforeign income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law or interpretation on us. Changes in current state law may subject us to additional entity level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any such taxes may substantially reduce the value of our common units.

Although we monitor our level of non-qualifying income closely and attempt to manage our operations to ensure compliance with the qualifying income requirement, given the continued weak demand and low prices for met and steam coal, there is a risk that we will not be able to continue to meet the qualifying income level necessary to maintain our status as a partnership for federal income tax purposes.

As a publicly traded partnership, we may be treated as a corporation for federal income tax purposes unless 90% or more of our gross income in each year consists of certain identified types of "qualifying“qualifying income."” In addition to qualifying income, like many other publicly traded partnerships, we also generate ancillary income that may not constitute qualifying income. Although we monitor our level of gross income that may not constitute qualifying income closely and attempt to manage our operations to ensure compliance with the qualifying income requirement, given the continued weak demand and low prices for met and steam coal, the sale of which generates qualifying income, there is a risk that we will not be able to continue to meet the qualifying income level necessary to maintain our status as a publicly-traded partnership. To the extent we become aware that we may not generate or have not generated sufficient qualifying income with respect to a tax period, we can and would take action to preserve our treatment as a partnership for federal income tax purposes, including seeking relief from the IRS. Section 7704(e) of the Internal Revenue Code provides for the possibility of relief upon, among other things, determination by the IRS that such failure to meet the qualifying income requirement was inadvertent. However, we are unaware of examples of such relief being sought by a publicly traded partnership.

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

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. For example, the Obama administration's budget proposal for fiscal year 2017 recommends that certain publicly traded partnerships earning income from activities related to fossil fuels be taxed as corporations beginning in 2022. From time to time, members of Congress propose and consider such substantive changes to the existing federal income tax laws that would affect publicly traded partnerships. If successful, the Obama administration'spartnerships, including a prior legislative proposal or other similar proposals, could eliminatewould have eliminated the qualifying income exception to the treatment of all publicly traded

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partnerships as corporations upon which we rely for our treatment as a partnership for U.S. federal income tax purposes.

In addition, the Internal Revenue ServiceTreasury Department has been consideringissued, and in the future may issue, regulations interpreting those laws that affect publicly traded partnerships. Although there are no current legislative or administrative proposals, there can be no assurance that there will not be further changes to its private letter ruling policy concerning which activities give rise toU.S. federal income tax laws or the Treasury Department’s interpretation of the qualifying income withinrules in a manner that could impact our ability to qualify as a publicly traded partnership in the meaning of section 7704 of the Code. The implementation of changes to this policy could include the modification or revocation of existing rulings, including ours.future.

Any modificationsmodification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units. You are urged to consult with your own tax advisor with respect to the status of regulatory or administrative developments and proposals and their potential effect on your investment in our common units.

If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest may substantially reduce the value ofour cash available for distribution to our common units. Recently enacted legislation alters the procedures for assessing and collecting taxes due for taxable years beginning after December 31, 2017, in a manner that could substantially reduce the value of our common units.unitholders.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for U.S. federal income tax purposes or any other matter affecting us.purposes. The IRS may adopt positions that differ from the positions we take.take and it may be necessary to resort to administrative or court proceedings to sustain some or all of our positions. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. OurMoreover, the costs of any contest with the IRS will reduce our cash available for distribution to our common unitholders and thus will be borne indirectly by our unitholderscommon unitholders. We have requested and obtained a favorable private letter ruling from the IRS to the effect that, based on facts presented in the private letter ruling request, income from management fees, cost reimbursements and cost-sharing payments related to our general partner becausemanagement and operation of mining, production, processing, and sale of coal and from energy infrastructure support services will constitute “qualifying income” within the costs may substantially reducemeaning of Section 7704 of the value of our common unitsCode.

 Recently enacted legislation applicable

If the IRS makes audit adjustments to usour income tax returns for taxabletax years beginning after December 31, 2017, alters the procedures for auditing large partnershipsit (and some states) may assess and also alters the procedures for assessing and collectingcollect any taxes due (including any applicable penalties and interest) as a result of an audit. Unless we are eligible to (and choose to) elect to issue revised Schedules K-1resulting from such audit adjustments directly from us, in which case our cash available for distribution to our partners with respectunitholders might be substantially reduced and our current and former unitholders may be required to an auditedindemnify us for any taxes (including any applicable penalties and adjusted return,interest) resulting from such audit adjustments that were paid on such unitholders’ behalf.

Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustments directly from us. To the extent possible under the new rules, our general partner may elect to either pay the taxes (including any applicable penalties and interest) directly to the IRS or, if we are eligible, issue a revised information statement to each unitholder and former unitholder with respect to an audited and adjusted return. Although our general partner may elect to have our unitholders and former unitholders take such audit adjustment into account and pay any resulting taxes (including applicable penalties or interest) in accordance with their interests in us during the tax year under audit, there can be no assurance that such election will be practical, permissible or effective in all circumstances. As a result, our current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own units in us induring the tax year in which theunder audit. If, as a result of any such audit is completed under the new rules. Ifadjustment, we are required to paymake payments of taxes, penalties and interest, as the result ofour cash available for distribution to our unitholders might be substantially reduced and our current and former unitholders may be required to indemnify us for any taxes (including any applicable penalties and interest) resulting from such audit adjustments the value of our common units may be substantially reduced. In addition, because payment would be duethat were paid on such unitholders’ behalf. These rules are not applicable for the taxable year in which the audit is completed, unitholders during that taxable year would bear the expense of the adjustment even if they were not unitholders during the audited taxable year.tax years beginning on or prior to December 31, 2017.

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

Our common unitholders are required to pay federal income taxes and, in some cases, state and local income taxes, on their share of our taxable income, whether or not they receive cash distributions from us. Our common unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax due with respect to that income.

We anticipate engaging in transactions to reduce our indebtedness and manage our liquidity that generate taxable income (including cancellation of indebtedness income) allocable to common unitholders, and income tax liabilities arising therefrom may exceed the value of your investment in us.

In response to current market conditions, from time to time we may consideranticipate engaging in transactions to delever us and manage our liquidity that would result in income and gain to our common unitholders without a corresponding cash distribution. For example, we may sell assets and use the

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proceeds to repay existing debt or fund capital expenditures, in which case, you would be allocated taxable income and gain resulting from the sale without receiving a cash distribution. Further, we may pursueanticipate pursuing opportunities to reduce our existing debt, such as debt exchanges, debt repurchases, or modifications and extinguishment of our existing debt that would result in "cancellation“cancellation of indebtedness income"income” (also referred to as "COD income"“COD income”) being allocated to our common unitholders as ordinary taxable income. UnitholdersCommon unitholders may be allocated COD income, and income tax liabilities arising therefrom may exceed the current value of your investment in us.

Entities taxed as corporations may have net operating losses to offset COD income or may otherwise qualify for an exception to the recognition of COD income, such as the bankruptcy or insolvency exceptions. As long as we are treated as a partnership, however, these exceptions are not available to the partnership and are only available to a common unitholder if the common unitholder itself is insolvent or in bankruptcy. As a result, these exceptions generally would not apply to prevent the taxation of COD income allocated to our common unitholders. The ultimate tax effect of any such income allocations will depend on the unitholder'scommon unitholder’s individual tax position, including, for example, the availability of any suspended passive losses that may offset some portion of the allocable COD income. UnitholdersCommon unitholders may, however, be allocated substantial amounts of ordinary income subject to taxation, without any ability to offset such allocated income against any capital losses attributable to the unitholder'scommon unitholder’s ultimate disposition of its units. UnitholdersCommon unitholders are encouraged to consult their tax advisors with respect to the consequences to them of COD income.

Tax gain or loss on the disposition of our common units could be more or less than expected.