ROYE Royal Energy Resources Inc (CE)

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

A decline in coal prices could adversely affect our results of operations and our ability to receive cash distributions from the Partnership.

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. The prices we receive for coal depend upon factors beyond our control, including:

Any adverse change in these factors could result in weaker demand and lower prices for our products. In addition, global financial and credit market disruptions, have 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. If these trends continue, 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.

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.

The Partnership performed a comprehensive review of our coal mining operation as well as potential future development projects for the year ended December 31, 2018 to ascertain any potential impairment losses. We did not record any impairment losses for coal properties, mine development costs or coal mining equipment and related facilities for the year ended December 31, 2018.

The Partnership performed a comprehensive review of its current coal mining operation as well as potential future development projects for the year ended December 31, 2017 to ascertain any potential impairment losses. The Partnership engaged an independent third party to perform a fair market value appraisal on certain parcels of land that it owns in Mesa County, Colorado. The parcels appraised for $6.0 million compared to the carrying value of $6.8 million. The Partnership recorded an impairment loss of $0.8 million, which is recorded on the Asset impairment and related 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.

The Partnership also recorded an impairment charge of $21.8 million related to the call option received from a third party to acquire substantially all of the outstanding common stock of Armstrong Energy, Inc. On October 31, 2017, Armstrong Energy filed Chapter 11 petitions in the Eastern 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 as such we concluded that the call option had no carrying value. An impairment charge of $21.8 million related to the call option has been recorded on the Asset impairment and related charges line of the consolidated statements of operations and comprehensive income.

We completed a comprehensive review of all coal assets beyond those related to the Partnership and identified one impairment in 2018 and various impairments in 2017. Based on the impairment analysis, we concluded that the ARQ royalty interest was impaired. As production from this property had not begun at December 31, 2018 or December 31, 2017, we conducted an impairment assessment. At December 31, 2018, the Company adjusted the value to $0. At December 31, 2017, the Company adjusted the value to $1.8 million based on an option that we granted to ARQ to purchase the royalty interest, which triggered a fourth quarter 2017 impairment loss of $2.6 million. The option subsequently expired leading to the remaining 2018 impairment charge.

Additionally, at December 31, 2017, management determined that its investment in Blaze Minerals was impaired and removed the entire investment and associated assets from the consolidated financial statements. Accordingly, we recorded an additional asset impairment loss of $7 million in the fourth quarter of 2017.

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 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.

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 our ability to receive cash distributions from the Partnership.

Steam coal accounted for approximately 81% of our coal sales volume for the year ended December 31, 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 benefits 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 our ability to receive cash distributions from the Partnership.

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 our ability to receive cash distributions from the Partnership, either through direct impacts such as those regulating our existing mining operations, or indirect impacts such as those that discourage or limit our 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” under applicable environmental laws and have the potential to 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”), 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”), 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”) issued new or more stringent rules and policies on a variety of topics, including:

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 had a phased implementation schedule, and the third and final phase of the rule became effective in August 2016. Under the phased approach, operators were required to adopt new measures and procedures for dust sampling, record keeping, and medical surveillance. Additionally, in September 2015, MSHA issued a proposed rule requiring the installation of proximity detection systems coal hauling machines and scoops. The rulemaking record for this proposed rule was closed on December 15, 2016, but on January 9, 2017, MSHA published a notice reopening the record and extending the comment period for this proposed rule for 30 days. 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’ 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 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 our ability to receive cash distributions from the Partnership and could result in harsher sanctions in the event of any violations. Please read “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 result in increased civil penalty assessments for medium and larger mine operators and contractors by 300% to 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.

We have in the past, and may in the future, be subject to fines, penalties or sanctions resulting from alleged violations of MSHA regulations. Any of our mines could be subject to a temporary or extended shut down as a result of an alleged MSHA violation. Any future 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 continuance of ongoing mining operations or the development of future mining operations. For example, final guidance released by the CEQ regarding climate change considerations in the NEPA analyses may increase the likelihood of future challenges to the NEPA documents prepared for actions requiring federal approval. 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 (“WOTUS”). Expansion of EPA jurisdiction over these areas has the potential to adversely impact our operations. 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. Please read “Part I, Item 1. Business—Regulation and Laws—Clean Water Act.” For now, EPA and the Corps will continue to apply the existing standard for what constitutes a water of the United States as determined by the Supreme Court in the Rapanos case and post-Rapanos guidance. Should the 2015 rule take effect, or should a different rule expanding the definition of what constitutes a water of the United States be promulgated as a result of EPA and the 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:

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 operating cash flow.

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 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 our ability to receive cash distributions from the Partnership.

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’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 our ability to receive cash distributions from the Partnership.

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 our ability to receive cash distributions from the Partnership.

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 our ability to receive cash distributions from the Partnership.

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 prices decrease or our labor prices increase, our results of operations and our ability to receive cash distributions from the Partnership 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 our ability to receive cash distributions from the Partnership could be adversely affected.

Our results of operations and our ability to receive cash distributions from the Partnership 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 our ability to receive cash distributions from the Partnership. 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 factors and assumptions, all of which may vary considerably from actual results. These factors and assumptions relate to:

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.

The Partnership invests in non-coal natural resource assets, which could result in a material adverse effect on its results of operations and our ability to receive cash distributions from the Partnership.

Part of the Partnership’s business strategy is to expand its operations through strategic acquisitions, which includes investing in non-coal natural resources assets. Its executive officers do not have experience investing in or operating non-coal natural resources assets and it may be unable to hire additional management with relevant expertise in operating such assets. Acquisitions of non-coal natural resource assets could expose the Partnership to new and additional operating and regulatory risks, including commodity price risk, which could result in a material adverse effect on its results of operations and our ability to receive cash distributions from the Partnership.

The amount of estimated maintenance capital expenditures the Partnership 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 us by the Partnership.

The Partnership’s partnership agreement requires that it 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. Its annual estimated maintenance capital expenditures for purposes of calculating operating surplus is based on its estimates of the amounts of expenditures it will be required to make in the future to maintain its long-term operating capacity. Its partnership agreement does not cap the amount of maintenance capital expenditures that its general partner may estimate. The amount of its estimated maintenance capital expenditures may be more than its actual maintenance capital expenditures, which will reduce the amount of available cash from operating surplus that it would otherwise have available for distribution to unitholders, including Royal. The amount of estimated maintenance capital expenditures deducted from operating surplus is subject to review and change by the Partnership’s board of directors at least once a year, with any change approved by the Partnership’s conflicts committee.

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 our ability to receive cash distributions from the Partnership.

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 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 CO ₂ , 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.”

For example, on the international level, the United States is 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.

At the federal level, EPA has finalized a number of rules related to GHG emissions. For example, the EPA issued rules that establish carbon pollution standards for power plants, called CO ₂ emission performance rates. Judicial challenges led the U.S. Supreme Court to grant a stay of the implementation of the CPP in February 2016. By its terms, this stay will remain in effect throughout the pendency of the appeals process. The stay suspends the rule, including the requirement that states submit their initial plans by September 2016. The Supreme Court’s stay applies only to EPA’s regulations for CO ₂ emissions from existing power plants and will not affect EPA’s standards for new power plants. It is not yet clear how the courts 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. The ANPRM seeks comment regarding what the EPA should include in a potential new, existing-source regulation under the Clean Air Act of GHG emissions from electric utility generating units that it may propose. If the effort to repeal the rules is unsuccessful and the rules were upheld at the conclusion of the appellate process and were implemented in their current form, or if the ANPRM results in a different proposal to control 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’s rules for new power plants. The EPA’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 the Partnership mines and sells, 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”), calling for implementation of a cap and trade program aimed at reducing carbon dioxide emissions from power plants in the participating states. . Following the RGGI model, several western states and Canadian provinces have confirmed a commitment and timetable to create a carbon market in North 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 due 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’s Environmental Appeals Board. In addition, over 30 states have adopted mandatory “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.

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 CCS technology have been proposed or enacted. For example, in October 2015, the EPA released a rule that established, for the first time, new source performance standards under the federal Clean Air Act for CO2 emissions from new fossil fuel-fired electric utility generating power plants. 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 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 available control technology” or “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 our ability to receive cash distributions from the Partnership.

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 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 the Partnership or their customers operate, they could have an adverse effect on their 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 our ability to receive cash distributions from the Partnership.

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”) 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:

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, 2018, we had approximately $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, if there 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 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 any amounts received may be inadequate. If we do not maintain sufficient borrowing capacity or have other resources to satisfy our surety and bonding requirements, our operations 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 our ability to receive cash distributions from the Partnership could be adversely affected.

We sell a material portion of our coal under supply contracts. As of December 31, 2018, we had sales commitments for approximately 74% of our estimated coal production (including purchased coal to supplement our production) for the year ending December 31, 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 61% in 2019, and 33% in 2020, and 6% in 2021. We derived approximately 80.5% of our total coal revenues from coal sales to our ten largest customers for the year ended December 31, 2018, with affiliates of our top three customers accounting for approximately 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’ 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 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” 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 our ability to receive cash distributions from the Partnership.

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.

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.

If we sustain cyber-attacks or other security breaches that disrupt our operations, or that result in the unauthorized release of proprietary 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 the Partnership. The loss of the services of any member of senior management or key employee could have an adverse effect on our business. Furthermore, the loss of the services of certain key management of the Partnership could reduce its ability to make distributions to us. 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 II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates—Asset Retirement Obligations.”

The Partnership’s debt levels may limit its flexibility in obtaining additional financing and in pursuing other business opportunities.

The Partnership’s level of indebtedness could have important consequences to us, including the following:

Increases in the Partnership’s total indebtedness would increase its total interest expense, which would in turn reduce its forecasted cash available for distribution. As of December 31, 2017 its current portion of long-term debt that will be funded from cash flows from operating activities during 2018 was approximately $0.4 million. Its ability to service its indebtedness will depend upon, among other things, its 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 its control. If its operating results are not sufficient to service its current or future indebtedness, it will be forced to take actions such as reducing or delaying its business activities, acquisitions, investments, capital expenditures, and/or expense reimbursements to Royal, selling assets, restructuring or refinancing its indebtedness, or seeking additional equity capital or bankruptcy protection. The Partnership may not be able to effect any of these remedies on satisfactory terms, or at all.

The Partnership’s financing agreement contains operating and financial restrictions that may restrict its business and financing activities and limit its ability to pay distributions upon the occurrence of certain events.

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

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

Any subsequent refinancing of its current debt or any new debt could have similar restrictions. Its ability to comply with the covenants and restrictions contained in its credit agreement may be affected by events beyond its control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, its ability to comply with these covenants may be impaired. If we violate any of the restrictions, covenants, ratios or tests in its credit agreement, a significant portion of its indebtedness may become immediately due and payable, and its 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, its obligations under its credit agreement will be secured by substantially all of its assets, and if we are unable to repay its indebtedness under its credit agreement, the lenders could seek to foreclose on such assets. For more information, please read “Part I, Item 1. 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 uninterrupted operation of its information technology (“IT”) systems. User access of our sites and IT 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 our activities, and could adversely affect our reputation, operations or financial performance.

Potential risks to the our IT systems could include unauthorized attempts to extract business sensitive, confidential or personal information, denial of access 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

Concentration of ownership among our existing directors, executive officers and principal stockholders may prevent new investors from influencing significant corporate decisions.

Our current directors and executive officers and their respective affiliates will, in the aggregate, beneficially own or control approximately 52.9% of our outstanding common stock and 100% of our outstanding Series A Preferred Stock. Because of the special voting rights of our Series A Preferred Stock (which is entitled to 54% of the total votes on any matter on which shareholders have a right to vote), William L. Tuorto currently controls 75.5% of the votes on any matter requiring a shareholder vote. As a result, these stockholders will be able to exercise a controlling influence over matters requiring stockholder approval, including the election of directors and approval of significant corporate transactions, and will have significant influence over our management and policies for the foreseeable future. Some of these persons or entities may have interests that are different from yours. For example, these stockholders may support proposals and actions with which you may disagree or which are not in your interests. The concentration of ownership could delay or prevent a change in control of our company or otherwise discourage a potential acquirer from attempting to obtain control of our company, which in turn could reduce the price of our common stock. In addition, these stockholders, some of which have representatives sitting on our board of directors, could use their voting control to maintain our existing management and directors in office, delay or prevent changes of control of our company, or support or reject other management and board of director proposals that are subject to stockholder approval, such as amendments to our employee stock plans and approvals of significant financing transactions.

There Is A Limited Market For Our Common Stock.

Our common stock is currently quoted on the OTCQB under the symbol “ROYE.” The trading market for our common stock is limited. We are exploring a possible listing of our common stock on the NASDAQ, which may improve the trading market for our common stock. However, there is no assurance that we will be approved for listing or that the listing will improve the trading market for our common stock. A more active trading market for our common stock may never develop, or if such a market develops, it may not be sustained.

Our common stock, and the Partnership’s common units, are currently traded on the OTCQB, which could adversely affect the market liquidity of our common stock and common units, respectively, and harm our business.

Our common stock trades on the OTCQB under the ticker symbol “ROYE.” The Partnerships common units trade on the OTCQB under the ticker symbol “RHNO.” Our common stock and the Partnership’s common units 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 shareholders and the Partnership’s unitholders:

Further, since neither us nor the Partnership are traded on a national securities exchange, we are not subject to exchange rules, including rules requiring that either us or the Partnership meet certain corporate governance standards. Without required compliance of these corporate governance standards, investor interest in our common stock or the Partnership’s common units may decrease.

The Partnership does not have sufficient cash to enable it to pay the minimum quarterly distribution on its common units following establishment of cash reserves and payment of costs and expenses, including reimbursement of expenses to its general partner.

Currently, Royal’s only operations consist of the coal mining operations of the Partnership, although Royal currently receive royalties under a royalty agreement covering a coal transloading facility on the Ohio River. As a result, Royal is substantially dependent on the Partnership to generate cash flow that can be used to pay distributions or expense reimbursements that Royal can use to pay its own operating expenses and indebtedness. The Partnership’s ability to generate operating cash flow that can be used to pay distributions or expense reimbursements to Royal is subject to all of the risks inherent in the Partnership’s business, including covenants in the Partnership’s Financing Agreement. If the Partnership is unable to pay distributions or expense reimbursements to Royal, Royal may not have sufficient funds to pay its own operating expenses or repay its indebtedness. If Royal is unable to receive sufficient distributions or expense reimbursements from the Partnership, Royal may have to raise capital from third parties to pay its liabilities. There is no assurance that Royal would be able to raise capital on terms that are not dilutive to existing shareholders, or at all.

Currently, the Partnership does not have sufficient cash each quarter to pay its minimum quarterly distribution of $4.45 per unit, or $17.80 per unit per year, which would require that it have available cash of approximately $58.6 million per quarter, or $234.2 million per year, based on the number of common and subordinated units outstanding as of December 31, 2018 and the general partner interest. Beginning with the quarter ended September 30, 2014, distributions on its common units were below the minimum level and, beginning with the quarter ended June 30, 2015, it suspended the quarterly distribution on its common units altogether, and has not paid any quarterly distributions since. The amount of cash it can distribute on its common and subordinated units principally depends upon the amount of cash it generates from its operations, which will fluctuate from quarter to quarter based on, among other things:

The failure of the Partnership to pay distributions on its common units could impair our ability to our obligations that are incurred outside of the Partnership, including our loan from Cedarview and our general and administrative expenses. In addition, the failure of the Partnership to pay distributions on its common units could be a factor in depressing the market value of its common units, which could result in dilution of our interest in the Partnership as a result of the conversion into common units of the Series A Preferred Units of the Partnership whose conversion price is based on the market price of the common units at the time of conversion.

Because the market may respond to our business operations and that of our competitors, our stock price will likely be volatile.

The OTCQB is a network of security dealers who buy and sell stock. The dealers are connected by a computer network that provides information on current “bids” and “asks”, as well as volume information. We anticipate that the market price of our common stock will be subject to wide fluctuations in response to several factors, including: our ability to economically exploit our properties successfully; increased competition from competitors; and our financial condition and results of our operations.

We do not intend to pay dividends for the foreseeable future.

We have never declared or paid any dividends on our common stock. We intend to retain all of our earnings for the foreseeable future to finance the operation and expansion of our business, and we do not anticipate paying any cash dividends in the future. As a result, you may only receive a return on your investment in our common stock if the market price of our common stock increases. Our board of directors retains the discretion to change this policy.

An increase in interest rates may cause the market price of our common shares to decline.

Like all equity investments, an investment in our common shares is subject to certain risks. In exchange for accepting these risks, investors may expect to receive a higher rate of return than would otherwise be obtainable from lower-risk investments. Accordingly, as interest rates rise, the ability of investors to obtain higher risk-adjusted rates of return by purchasing government-backed debt securities may cause a corresponding decline in demand for riskier investments generally. Reduced demand for our common shares resulting from investors seeking other more favorable investment opportunities may cause the trading price of our common shares to decline.

Additional equity or debt financing may be dilutive to existing stockholders or impose terms that are unfavorable to us or our existing stockholders.

We will need to raise substantial capital in order to finance the acquisition of coal properties, provide working capital, and create reserves against the many contingencies that are inherent in the mining industry. If we raise additional funds by issuing equity securities, our stockholders will experience dilution. Debt financing, if available, may involve arrangements that include covenants limiting or restricting our ability to take specific actions, such as incurring additional debt, making capital expenditures or declaring dividends. Any debt financing or additional equity that we raise may contain terms, such as liquidation and other preferences that are not favorable to us or our current stockholders.

We depend on key personnel and could be harmed by the loss of their services because of the limited number of qualified people in our industry.

Because of our small size, we require the continued service and performance of our management team, all of whom we consider to be key employees. Competition for highly qualified employees in the mining industry is intense. Our success will depend to a significant degree upon our ability to attract, train, and retain highly skilled directors, officers, management, business, financial, legal, marketing, sales, and technical personnel and upon the continued contributions of such people. In addition, we may not be able to retain our current key employees. The loss of the services of one or more of our key personnel and our failure to attract additional highly qualified personnel could impair our ability to expand our operations and provide service to our customers.

Under the terms of our Certificate of Incorporation, our Board of Directors is authorized to issue shares of preferred stock with rights and privileges superior to common stockholders without common stockholder approval.

Under the terms of our Certificate of Incorporation, our board of directors is authorized to issue shares of preferred stock in one or more classes or series without stockholder approval. The board has discretion to set the terms, preferences, conversion or other rights, voting powers, restrictions, limitations as to dividends or other distributions, qualifications and terms or conditions of redemption for each class or series of preferred stock. Accordingly, we may designate and issue additional shares or series of preferred stock that would rank senior to the shares of common stock as to dividend rights or rights upon our liquidation, winding-up, or dissolution.

Provisions in Our Certificate of Incorporation and Bylaws and Delaware law May Inhibit a Takeover of Us, Which Could Limit the Price Investors Might Be Willing to Pay in the Future for our Common Stock and Could Entrench Management.

Our certificate of incorporation and bylaws contain provisions that may discourage unsolicited takeover proposals that stockholders may consider to be in their best interests. Our board has authorized the issuance of 100,000 shares of one class of preferred stock, known as “Series A Preferred Stock.” The Series A Preferred Stock has voting rights entitling it to 54% of the total votes on any matter on which stockholders are entitled to vote. In addition, we cannot authorize or issue any class of capital stock or bonds, debentures, notes or other securities or other obligations ranking senior to or on a parity with the Series A Preferred Stock without the approval of the Series A Preferred Stock voting as a separate class. Mr. Tuorto holds all of the outstanding shares of Series A Preferred Stock. As a result, at any meeting of shareholders Mr. Tuorto has a disproportionate voting power.

Mr. Tuorto’s control of our Series A Preferred Stock may prevent our stockholders from replacing a majority of our board of directors at any shareholder meeting, which may entrench management and discourage unsolicited stockholder proposals that may be in the best interests of stockholders. Moreover, our board of directors has the ability to designate the terms of and issue new series of preferred stock without stockholder approval.

In addition, as a Delaware corporation, we are subject to Section 203 of the Delaware General Corporation Law, which generally prohibits a Delaware corporation from engaging in any business combination with any interested stockholder for a period of three years following the date that the stockholder became an interested stockholder, unless certain specific requirements are met as set forth in Section 203. Collectively, these provisions may make more difficult the removal of management and may discourage transactions that otherwise could involve payment of a premium over prevailing market prices for our securities.

The Series A preferred units of the Partnership 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 interest in the Partnership.

The Series A preferred units of the Partnership are a new class of partnership interests that rank senior to its common units with respect to distribution rights and rights upon liquidation. The Partnership is 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 its 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 the Partnership from its Central Appalachia business segment) and (ii) an amount equal to the number of outstanding Series A preferred units multiplied by $0.80. If the Partnership fails to pay any or all of the distributions in respect of the Series A preferred units, such deficiency will accrue until paid in full and it will not be permitted to pay any distributions on Royal’s partnership interests that rank junior to the Series A Preferred Units, including its 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.

The Partnership may convert the Series A preferred units into common units at any time on or after the time at which the amount of aggregate distributions paid in respect of each Series A Preferred Unit exceeds $10.00 per unit. All unconverted Series A preferred units will convert into common units on December 31, 2021. The number of common units issued in any conversion will be based on the volume-weighted average closing price of the common units for 90 days preceding the date of conversion. Accordingly, the lower the trading price of the Partnership’s common units over the 90 day measurement period, the greater the number of common units that will be issued upon conversion of the preferred units, which would result in greater dilution to our interest in the Partnership. Dilution has the following effects on our interest in the Partnership:

Holders of the Partnership’s Series A Preferred Units have substantial negative control rights.

For as long as the Series A preferred units are outstanding, the Partnership 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 its Central Appalachia business segment, subject to certain exceptions. These consent rights effectively add a constituency to the Partnership’s fundamental decision-making process, and failure to obtain such consent from the Series A preferred holders could prevent the Partnership from taking actions that its management or board of directors otherwise view as prudent or necessary for its business operations or the execution of its business strategy.

The market price of our common stock could be adversely affected by sales of substantial amounts of our common stock in the public or private markets, including sales by our officers and directors.

As of March 20, 2019, we had 18,579,293 shares of common stock (including 914,797 shares held by its consolidated subsidiary, Rhino Resource Partners, LP) and 51,000 shares of Series A Preferred Stock outstanding. All of the Series A Preferred Shares are convertible into common stock on a one for one basis. Approximately 50.5% of our common stock is owned or controlled by our officers and directors, including approximately 45.4% by William Tuorto and entities he controls. There is currently only a limited market for our commons stock. Sales by our large holders of a substantial number of shares 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 stock or could impair our ability to obtain capital through an offering of equity securities.

Income Tax Risks

We failed to timely file certain prior years’ state and federal tax returns.

We failed to file federal and state tax returns on a timely basis since the tax year ending August 31, 2014. While we have since filed the federal returns and the state returns are in process, we acknowledge that past due penalties and interest may be due. We have recorded tax provisions based on our estimates, but the ultimate tax provisions could vary materially from the estimates provided in the accompanying consolidated financial statements.

We were deficient in filing an appropriate change in tax year from August year end to a December year end.

We failed to file a timely election to change our tax year end from August 31 to December 31. We have since filed a request to change our tax year end from August 31, to December 31. While we believe we have sufficient grounds to change our tax year end to December 31, since the Partnership has a December 31 year end for tax and financial reporting purposes, our request is subject to the discretionary approval of the IRS. If the IRS denies our request, the IRS could force us to amend tax returns to comply with our previous August 31 tax year end reporting period. Our ultimate tax obligation could vary materially based on the ultimate tax filing year due to substantial changes to the corporate tax rates and other corporate tax law provisions passed by Congress in December 2017 (See below for more information about the Act).

The Rhino investment may provide taxable income with no tax distributions.

During 2017, Royal had taxable income allocated from its ownership in Rhino, which we expect to offset, in part, against our prior year net operating losses. It is possible that taxable income generated by the Partnership allocation in future tax years will exceed our net operating loss offsets or tax distributions from the Partnership. If that occurs, we may need to raise capital or sell assets in order to generate funds to pay our taxes. There is no assurance that Royal would be able to raise capital on terms that are not dilutive to existing shareholders, or at all.

We may not be able to fully utilize our deferred tax assets.

We are subject to income and other taxes in the U.S. As of December 31, 2018, we had gross deferred income tax assets, including net operating loss carryforwards for federal and state tax purposes, of $20.8 million and $10.2 million, respectively, as described further in “Note 14. Income Taxes” to the accompanying consolidated financial statements. At that date, we also had recorded a valuation allowance of $1.7 million. Although we may be able to utilize some or all of those deferred tax assets in the future if we have income of the appropriate character (subject to loss carryforward and tax credit expiry, in certain cases), there is no assurance that we will be able to do so.

Rhino’s tax treatment depends on its status as a partnership for federal and state income tax purposes, as Rhino is not subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service (“IRS”) were to treat Rhino as a corporation for federal income tax purposes, or it becomes subject to entity-level taxation for state tax purposes, then its cash available for distribution to unitholders, including Royal would be substantially reduced.

The anticipated after-tax economic benefit of Royal’s investment in Rhino’s common units depends largely on Rhino being treated as a partnership for U.S. federal income tax purposes. Despite the fact that Rhino is organized as a limited partnership under Delaware law, it will be treated as a corporation for federal income tax purposes unless it satisfies a “qualifying income” requirement. Based on current operations, Rhino believes that it satisfies the qualifying income requirement and will be treated as a partnership. Rhino may, however, decide that it is in its best interest to be treated as a corporation for federal income tax purposes. Failing to meet the qualifying income requirement, a change in current law, or an election to be treated as a corporation, could cause Rhino to be treated as a corporation for federal income tax purposes or otherwise subject it to taxation as an entity.

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. Rhino currently owns assets and conducts business in several states that impose a margin or franchise tax. In the future, Rhino may expand its operations to other states. Imposition of a similar tax on it in jurisdictions to which it expands could substantially reduce its cash available for distribution to its unitholders, including. The partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects it to additional amounts of entity level taxation for U.S. federal, state, local, or foreign 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 Rhino. Changes in current state law may subject Rhino to additional entity level taxation by individual states.

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

As a publicly traded partnership, Rhino may be treated as a corporation for federal income tax purposes unless 90% or more of its gross income in each year consists of certain identified types of “qualifying income.” In addition to qualifying income, like many other publicly traded partnerships, Rhino also generates ancillary income that may not constitute qualifying income. Although Rhino monitors its level of gross income that may not constitute qualifying income closely and attempts to manage its operations to ensure compliance with the qualifying income requirement, given the continued low demand and low prices for met and steam coal, the sale of which generates qualifying income, there is a risk that Rhino will not be able to continue to meet the qualifying income level necessary to maintain its status as a publicly-traded partnership. To the extent Rhino becomes aware that it may not generate or have not generated sufficient qualifying income with respect to a tax period, Rhino can and would take action to preserve its 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, Rhino is unaware of examples of such relief being sought by a publicly traded partnership.

The tax treatment of publicly traded partnerships or an investment in its 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, or an investment in common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. For example, from time to time, members of Congress propose and consider substantive changes to the existing federal income tax laws that would affect publicly traded partnerships. Although there is no current legislative proposal, a prior legislative proposal would have eliminated the qualifying income exception to the treatment of all publicly traded partnerships as corporations upon which Rhino relies for its treatment as a partnership for U.S. federal income tax purposes.

In addition on January 24, 2017, final regulations regarding which activities give rise to qualifying income within the meaning of Section 7704 of the Code (the “Final Regulations”) were published in the Federal Register. The Final Regulations are effective as of January 19, 2017, and apply to taxable years beginning on or after January 19, 2017. We do not believe the Final Regulations affect Rhino’s ability to be treated as a partnership for U.S. federal income tax purposes.

However, any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for Rhino to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes. Rhino is unable to predict whether any of these changes or other proposals will ultimately be enacted. Any such changes could negatively impact the value of our investment in its common units.

If the IRS contests the federal income tax positions Rhino takes, the value of its common units may be adversely impacted and the cost of any IRS contest may substantially reduce its cash available for distribution to its unitholders.

Rhino has not requested a ruling from the IRS with respect to its treatment as a partnership for U.S. federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the positions Rhino takes and it may be necessary to resort to administrative or court proceedings to sustain some or all of its positions. A court may not agree with some or all of the positions Rhino takes. Any contest with the IRS may materially and adversely impact the value of our investment in its common units and the price at which they trade. Moreover, the costs of any contest with the IRS will reduce Rhino’s cash available for distribution to its unitholders, including Royal. Rhino has 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 its 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 Code.

If the IRS makes audit adjustments to Rhinos’ income tax returns for tax years beginning after December 31, 2017, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustments directly from Rhino, in which case its cash available for distribution to its unitholders might be substantially reduced and its current and former unitholders may be required to indemnify Rhino for any taxes (including any applicable penalties and interest) resulting from such audit adjustments that Rhino 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 its 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 Rhino. To the extent possible under the new rules, Rhino may elect to either pay the taxes (including any applicable penalties and interest) directly to the IRS or, if Rhino is eligible, issue a revised information statement to each unitholder and former unitholder with respect to an audited and adjusted return. Although Rhino may elect to have its 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 Rhino 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, its current unitholders, including Royal may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own units in Rhino during the tax year under audit. If, as a result of any such audit adjustment, Rhino is required to make payments of taxes, penalties and interest, its cash available for distribution to its unitholders might be substantially reduced and its current and former unitholders may be required to indemnify Rhino for any taxes (including any applicable penalties and interest) resulting from such audit adjustments that Rhino paid on such unitholders’ behalf. These rules are not applicable for tax years beginning on or prior to December 31, 2017.

Rhino’s unitholders are required to pay taxes on their share of their income even if they do not receive any cash distributions from Rhino.

Rhino’s unitholders, including Royal, are required to pay federal income taxes and, in some cases, state and local income taxes, on their share of taxable income, whether or not they receive cash distributions from Rhino. The unitholders may not receive cash distributions from Rhino equal to their share of its taxable income or even equal to the actual tax due with respect to that income.

Rhino anticipates engaging in transactions to reduce its indebtedness and manage its liquidity that generate taxable income (including cancellation of indebtedness income) allocable to unitholders, and income tax liabilities arising therefrom may exceed the value of Royal’s investment in Rhino.

In response to current market conditions, from time to time Rhino may consider engaging in transactions to deliver and manage its liquidity that would result in income and gain to its unitholders without a corresponding cash distribution. For example, Rhino may sell assets and use the proceeds to repay existing debt or fund capital expenditures, in which case, unitholders would be allocated taxable income and gain resulting from the sale without receiving a cash distribution. Further, Rhino may pursue opportunities to reduce its existing debt, such as debt exchanges, debt repurchases, or modifications and extinguishment of its existing debt that would result in “cancellation of indebtedness income” (also referred to as “COD income”) being allocated to its unitholders as ordinary taxable income. Royal may be allocated COD income, and income tax liabilities arising therefrom may exceed the current value of its investment in Rhino.

Because Royal is taxed as a corporation, it may have net operating losses to offset COD income. The ultimate tax effect of any such income allocations will depend on the 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. Royal 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 Royal’s ultimate disposition of its units.

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

If Royal sells Rhino’s units, it will recognize a gain or loss equal to the difference between the amount realized and its tax basis in those units. Because distributions in excess of its allocable share of its net taxable income decrease its tax basis in its units, the amount, if any, of such prior excess distributions with respect to the units sold will, in effect, become taxable income to Royal if it sells such units at a price greater than its tax basis in those units, even if the price received is less than its original cost. In addition, because the amount realized would include Royal’s share of its non-recourse liabilities, Royal may incur a tax liability in excess of the amount of cash received from the sale.

A substantial portion of the amount realized from the sale of Rhino units, whether or not representing gain, may be taxed as ordinary income to Royal due to potential recapture items, including depreciation recapture. Thus, Royal may recognize both ordinary income and capital loss from the sale of Rhino’s units if the amount realized on a sale of units is less than its adjusted basis in the units.

Net capital loss may only offset capital gains. In the taxable period in which Royal sells Rhino’s units, it may recognize ordinary income from its allocations of income and gain prior to the sale and from recapture items that generally cannot be offset by any capital loss recognized upon the sale of units.

Royal may be subject to limitations on its ability to deduct interest expense incurred by Rhino.

In general, Rhino is entitled to a deduction for interest paid or accrued on indebtedness properly allocable to its trade or business during its taxable year. However, under the Act, for taxable years beginning after December 31, 2017, its deduction for “business interest” is limited to the sum of its business interest income and 30% of its “adjusted taxable income.” For the purposes of this limitation, its adjusted taxable income is computed without regard to any business interest expense or business interest income, and in the case of taxable years beginning before January 1, 2022, any deduction allowable for depreciation, amortization, or depletion.

Rhino treats each purchaser of its common units as having the same tax benefits without regard to the common units actually purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

Because Rhino cannot match transferors and transferees of common units, Rhino has adopted certain methods of allocating depreciation and amortization deductions that may not conform to all aspects of the Treasury Regulations. A successful IRS challenge to the use of these methods could adversely affect the amount of tax benefits available to Royal. It also could affect the timing of these tax benefits or the amount of gain from its sale of common units and could have a negative impact on the value of its common units or result in audit adjustments to its tax returns.

Rhino generally prorates its items of income, gain, loss and deduction between transferors and transferees of its units each month based upon the ownership of its units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among its unitholders, including Royal.

Rhino generally prorates its items of income, gain, loss and deduction between transferors and transferees of its common units each month based upon the ownership of its units on the first day of each month (the “Allocation Date”), instead of on the basis of the date a particular common unit is transferred. Similarly, Rhino generally allocates gain or loss realized on the sale or other disposition of its assets or, in the discretion of Rhino, any other extraordinary item of income, gain, loss or deduction on the Allocation Date. Nonetheless, Rhino allocates certain deductions for depreciation of capital additions based upon the date the underlying property is placed in service. Treasury Regulations allow a similar monthly simplifying convention, but such regulations do not specifically authorize all aspects of its proration method. If the IRS challenged its proration method, Rhino could be required to change its allocation of items of income, gain, loss and deduction among its unitholders, including Royal.

Rhino has adopted certain valuation methodologies in determining a unitholder’s allocations of income, gain, loss and deduction. The IRS may challenge these methodologies or the resulting allocations, which could adversely affect the value of its common units.

In determining the items of income, gain, loss and deduction allocable to its unitholders, Rhino must routinely determine the fair market value of its assets. Although Rhino may, from time to time, consult with professional appraisers regarding valuation matters, Rhino makes many fair market value estimates using a methodology based on the market value of its common units as a means to measure the fair market value of its assets. The IRS may challenge these valuation methods and the resulting allocations of income, gain, loss and deduction.

A successful IRS challenge to these methods or allocations could adversely affect the timing or amount of taxable income or loss being allocated to its unitholders, including Royal. It also could affect the amount of gain from Royal’s sale of common units and could have a negative impact on the value of Royal’s investment in the common units or result in audit adjustments to Royal’s tax returns without the benefit of additional deductions.

Other Business Risks

Divestitures and acquisitions are a potentially important part of our long-term strategy, subject to our investment criteria, and involve a number of risks, any of which could cause us not to realize the anticipated benefits.

We may engage in divestiture or acquisition activity based on our set of investment criteria to produce outcomes that increase shareholder value. As it relates to divestitures, we may dispose of certain assets within our portfolio if we determine that the price received is more beneficial to us than keeping the assets within our portfolio. Conversely, acquisitions are a potentially important part of our long-term strategy, and we may pursue acquisition opportunities. If we fail to accurately estimate the future results and value of a divested or acquired business and the related risk associated with such a transaction, or are unable to successfully integrate the businesses or properties we acquire, our business, financial condition or results of operations could be negatively affected. Moreover, any transactions we pursue could materially impact our liquidity and an acquisition could increase capital resource needs and may require us to incur indebtedness, seek equity capital or both. We may not be able to satisfy these liquidity and capital resource needs on acceptable terms or at all. In addition, future acquisitions could result in our assuming significant long-term liabilities relative to the value of the acquisitions.

Diversity in interpretation and application of accounting literature in the mining industry may impact our reported financial results.

The mining industry has limited industry-specific accounting literature and, as a result, we understand diversity in practice exists in the interpretation and application of accounting literature to mining-specific issues. As diversity in mining industry accounting is addressed, we may need to restate our reported results if the resulting interpretations differ from our current accounting practices. Refer to Note 1. “Summary of Significant Accounting Policies” to the accompanying consolidated financial statements for a summary of our significant accounting policies.