The domestic electric utility industry accounts for over 93% of domestic coal 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 fuel oil as well as alternative sources of energy.  Gas-fueled generation has the potential to displace coal-fueled generation, particularly from older, less efficient coal-powered generators.  We expect that many of the new power plants needed in the U.S. to meet increasing demand for electricity generation will be fueled by natural gas because gas-fired plants are cheaper to construct and permits to construct these plants are easier to obtain.

Future environmental regulation of GHG emissions could accelerate the use by utilities of fuels other than coal.  In addition, state and federal mandates for increased use of electricity derived from renewable energy sources could affect demand for coal.  For example, the EPA’s CPP will likely incentivize additional electric generation from natural gas and renewable sources, and Congress has extended tax credits for renewables.  In addition, a number of states have enacted mandates that require electricity suppliers to rely on renewable energy sources in generating a certain percentage of power.  Such mandates, combined with other incentives to use renewable energy sources, such as tax credits, could make alternative fuel sources more competitive with coal.  A decrease in coal consumption by the domestic electric utility industry could adversely affect the price of coal, which could negatively impact our results of operations and reduce our cash from operations.

Extensive environmental laws and regulations affect coal consumers and have corresponding effects on the demand for coal as a fuel source.

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 coal-fired electric power plants, which are the ultimate consumers of much of our coal.  These laws and regulations can require significant emission control expenditures for many coal-fired power plants, and various new and proposed laws and regulations may require further emission reductions and associated emission control expenditures.  These laws and regulations may affect demand and prices for coal.  There is also continuing pressure on state and federal regulators to impose limits on carbon dioxide emissions from electric power plants, particularly coal-fired power plants.  Further, far-reaching federal regulations promulgated by the EPA in the last five years, such as CSAPR and MATS, have led to the premature retirement of coal-fired generating units and a significant reduction in the amount of coal-fired generating capacity in the U.S. 

Increased regulation of GHG emissions could result in increased operating costs and reduced demand for coal as a fuel source, which could reduce demand for our products, decrease our revenue and reduce our profitability.

Combustion of fossil fuels, such as the coal we produce, results in the emission of carbon dioxide into the atmosphere.  On December 15, 2009, the EPA published the Endangerment Finding asserting that emissions of carbon dioxide and other GHGs present an endangerment to public health and the environment, and the EPA has begun to regulate GHG emissions pursuant to the CAA.  The EPA has finalized an NSPS to regulate GHG emissions from new power plants.  The finalized standard requires CCS, a technology that is not yet commercially feasible without government subsidies and that has not been demonstrated in the marketplace.  This requirement effectively prevents the construction of new coal-fired power plants. The EPA published notice in the federal register in April 2017 that the agency has initiated a review of the NSPS for new and modified fossil fuel-fired power plants and that, following the review, the EPA will initiate reconsideration proceedings to suspend, revise or rescind this NSPS.  In August 2015, the EPA issued its final CPP rules that establish carbon pollution standards for existing power plants, called CO₂emission performance rates.  Judicial challenges led the U.S. Supreme Court to grant a stay in February 2016 of the implementation of the CPP before the Circuit Court even issued a decision.  By its terms, this stay will remain in effect throughout the pendency of the appeals process including at the Circuit Court and the Supreme Court through any certiorari petition that may be granted.  The Supreme Court's stay applies only to EPA's regulations for CO₂emissions from existing power plants and will not affect EPA's standards for new power plants.  It is not yet clear how either the Circuit Court or the Supreme Court 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 this proposed repeal, the EPA issued an 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 this 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 would likely be further decreased, potentially significantly, and our business would be adversely impacted. Please read “Item 1. Business—Regulation and Laws—Air Emissions” and “—Carbon Dioxide Emissions.”

Numerous political and regulatory authorities and governmental bodies, as well as 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 lending institutions 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. Some scientists have concluded 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.  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.

Federal, state and local governments may pass laws mandating the use of alternative energy sources, such as wind power and solar energy, which may decrease demand for our coal products.  The CPP is one of a number of recent developments aimed at limiting GHG emissions which could limit the market for some of our products by encouraging electric generation from sources that do not generate the same amount of GHG emissions.  Enactment of laws or passage of regulations regarding emissions from the combustion of coal by the U.S., states, or other countries, could also result in electricity generators further switching from coal to other fuel sources or additional coal-fueled power plant closures.  For example, the agreement resulting from the 2015 United Nations Framework Convention on Climate Change contains 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.

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.  Other activist campaigns have urged banks to cease financing coal-driven businesses.  As a result, several major banks 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.  Collectively, these actions and campaigns could adversely impact our future financial results, liquidity and growth prospects.

Government regulations have resulted and could continue to result in significant retirements of coal-fired electric generating units.  Retirements of coal-fired electric generating units decrease the overall capacity to burn coal and negatively impact coal demand.

Since 2010, utilities have formally announced the retirement or conversion of over 600 coal-fired electric generating units through 2030.  These retirements and conversions amount to over 111,000 megawatts (“MW”) or approximately 35% of the 2010 total coal electric generating capacity.  At the end of 2017 retirement and conversions affecting 69,000 MW, or approximately 22% of the 2010 total coal electric generating capacity, is estimated to have occurred.  Most of these announced and completed retirements and conversions have been attributed to the EPA regulations, although other factors such as an aging coal fleet and low natural gas prices have also played a role.  The reduction in coal electric capacity negatively impacts overall coal demand.  Additional regulations and other factors could lead to additional retirements and conversions and, thereby, additional reductions in the demand for coal.

Plaintiffs in federal court litigation have attempted to pursue tort claims based on the alleged effects of climate change.

In 2004, eight states and New York City sued five electric utility companies inConnecticut v. American Electric Power Co.  Invoking the federal and state common law of public nuisance; plaintiffs sought an injunction requiring defendants to abate their contribution to the nuisance of climate change by capping carbon dioxide emissions and then reducing them.  In June 2011, the U.S. Supreme Court issued a unanimous decision holding that the plaintiffs’ federal common law claims were displaced by federal legislation and regulations.  The U.S. Supreme Court did not address the plaintiffs’ state law tort claims and remanded the issue of preemption for the district court to consider.  While the U.S. Supreme Court held that federal common law provides no basis for public nuisance claims against utilities due to their carbon dioxide emissions, tort-type liabilities remain a possibility and a source of concern.  The proliferation of successful climate change litigation could adversely impact demand for coal and ultimately have a material adverse effect on our business, financial condition and results of operations.

The stability and profitability of our operations could be adversely affected if our customers do not honor existing contracts or do not extend existing or enter into new long-term contracts for coal.

In 2017, approximately 50%2021, the vast majority of our sales were under contracts having a term greater than one year, which we refer to as long-term contracts. Long-term sales contracts have historically provided a relatively secure market for the amount of production committed under the terms of the contracts. From time to time industry conditions may make it more difficult for us to enter into long-term contracts with our electric utility customers, and if supply exceeds demand in the coal industry, electric utilities may become less willing to lock in price or quantity commitments for an extended period of time. Accordingly, we may not be able to continue to obtain long-term sales contracts with reliable customers as existing contracts expire, which could subject a portion of our revenue stream to the increased volatility of the spot market.

Some of our long-term coal sales contracts contain provisions allowing for the renegotiation of prices and, in some instances, the termination of the contract or the suspension of purchases by customers.

Some of our long-term contracts contain provisions that allow for the purchase price to be renegotiated at periodic intervals. These price reopener provisions may automatically set a new price based on the prevailing market price or, in some instances, require the parties to the contract to agree on a new price. Any adjustment or renegotiation leading to a significantly lower contract price could adversely affect our operating profit margins. Accordingly, long-term contracts may provide only limited protection during adverse market conditions. In some circumstances, failure of the parties to agree on a price under a reopener provision can also lead to early termination of a contract.

Several of our long-term contracts also contain provisions that allow the customer to suspend or terminate performance under the contract upon the occurrence or continuation of certain events that are beyond the customer’s reasonable control. Such events may include labor disputes, mechanical malfunctions and changes in government regulations, including changes in environmental regulations rendering use of our coal inconsistent with the customer’s environmental compliance strategies. Additionally, most of our long-term contracts contain provisions requiring us to deliver coal within stated ranges for specific coal characteristics. Failure to meet these specifications can result in economic penalties, rejection or suspension of shipments or termination of the contracts. In the event of early termination of any of our long-term contracts, if we are unable to enter into new contracts on similar terms, our business, financial condition and results of operations could be adversely affected.

We depend on a few customers for a significant portion of our revenue, and the loss of one or more significant customers could affect our ability to maintain the sales volume and price of the coal we produce.

During 2017,2021, we derived 92%95% of our revenue from five customers and(10 power plants), with each of the five customers representing at least 10% of our revenue from each of them.coal sales. If in the future we were to lose any of these customers without finding replacement customers willing to purchase an equivalent amount of coal on similar terms, or if these customers were to decrease the amounts of coal purchased or the terms, including pricing terms, on which they buy coal from us, it could have a material adverse effect on our business, financial condition and results of operations.

Litigation resulting from disputes with our customers may result in substantial costs, liabilities, and loss of revenue.

From time to time we have disputes with our customers over the provisions of long-term coal supply contracts relating to, among other things, coal pricing, quality, quantity and the existence of specified conditions beyond our or our customers’ control that suspend performance obligations under the particular contract.  Disputes may occur in the future, and we may not be able to resolve those disputes in a satisfactory manner, which could have a material adverse effect on our business, financial condition and results of operations. 

Our ability to collect payments from our customers could be impaired if their creditworthiness declines or if they fail to honor their contracts with us.

Our ability to receive payment for coal sold and delivered depends on the continued creditworthiness of our customers. If the creditworthiness of our customers declines significantly, our business could be adversely affected. In addition, if a customer refuses to accept shipments of our coal for which they have an existing contractual obligation, our revenuerevenues will decrease, and we may have to reduce production at our mines until our customer’s contractual obligations are honored.

Our profitability may decline due to unanticipated mine operating conditions and other events that are not within our control and that may not be fully covered under our insurance policies.

Our mining operations are influenced by changing conditions or events that can affect production levels and costs at particular mines for varying lengths of time and, as a result, can diminish our profitability.  These conditions and events include, among others:

These conditions have the potential to significantly impact our operating results.  Prolonged disruption of production at any of our mines would result in a decrease in our revenue and profitability, which could materially adversely impact our quarterly or annual results.

Although none of our employees are members of unions, our workforce may not remain union-free in the future.

None of our employees are represented under collective bargaining agreements. However, all of our workforce may not remain union-free in the future, and legislative, regulatory or other governmental action could make it more difficult to remain union-free. If some or all of our currently union-free operations were to become unionized, it could adversely affect our productivity and increase the risk of work stoppages at our mining complexes. In addition, even if we remain union-free, our operations may still be adversely affected by work stoppages at unionized companies, particularly if union workers were to orchestrate boycotts against our operations.

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

We are subject to numerous federal, state and local laws and regulations affecting the coal mining industry, including laws and regulations pertaining to employee health and safety, permitting and licensing requirements, air and water quality standards, plant and wildlife protection, reclamation and restoration of mining properties after mining is completed, the discharge or release of materials into the environment, surface subsidence from underground mining and the effects that mining has on groundwater quality and availability.  Certain of these laws and regulations may impose strict liability without regard to fault or legality of the original conduct.  Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial liabilities, and the issuance of injunctions limiting or prohibiting the performance of operations.  Complying with these laws and regulations may be costly and time-consuming and may delay commencement or continuation of exploration or production operations.  The possibility exists that new laws or regulations may be adopted, or that judicial interpretations or more stringent enforcement of existing laws and regulations may occur, which could materially affect our mining operations, cash flow, and profitability, either through direct impacts on our mining operations, or indirect impacts that discourage or limit our customers’ use of coal.  Please read “Item 1. Business—Regulations and Laws.”

State and federal laws addressing mine safety practices impose stringent reporting requirements and civil and criminal penalties for violations.  Federal and state regulatory agencies continue to interpret and implement these laws and propose new regulations and standards.  Implementing and complying with these laws and regulations has increased and will continue to increase our operational expense and to have an adverse effect on our results of operation and financial position.  For more information, please read “Item 1. Business—Regulation and Laws—Mine Health and Safety Laws.”

We may be unable to obtain and renew permits necessary for our operations, which could reduce our production, cash flow and profitability.

Mining companies must obtain numerous governmental permits or approvals that impose strict conditions and obligations relating to various environmental and safety matters in connection with coal mining.  The permitting rules are complex and can change over time.  Regulatory authorities exercise considerable discretion in the timing and scope of permit issuance.  The public has the right to comment on permit applications and otherwise participate in the permitting process, including through court intervention.  Accordingly, permits required to conduct our operations may not be issued, maintained or renewed, or may not be issued or renewed in a timely fashion, or may involve requirements that restrict our ability to economically conduct our mining operations.  Limitations on our ability to conduct our mining operations due to the inability to obtain or renew necessary permits or similar approvals could reduce our production, cash flow, and profitability.  Please read “Item 1. Business—Regulations and Laws—Mining Permits and Approvals.”

The EPA has begun reviewing permits required for the discharge of overburden from mining operations under Section 404 of the CWA.  Various initiatives by the EPA regarding these permits have increased the time required to obtain and the costs of complying with such permits.  In addition, the EPA previously exercised its “veto” power to withdraw or restrict the use of previously issued permits in connection with one of the largest surface mining operations in Appalachia.  The EPA’s action was ultimately upheld by a federal court. As a result of these developments, we may be unable to obtain or experience delays in securing, utilizing or renewing Section 404 permits required for our operations, which could have an adverse effect on our results of operation and financial position.  Please read “Item 1. Business—Regulations and Laws—Water Discharge.”

In addition, some of our permits could be subject to challenges from the public, which could result in additional costs or delays in the permitting process, or even an inability to obtain permits, permit modifications or permit renewals necessary for our operations.

Fluctuations in transportation costs and the availability or reliability of transportation could reduce revenue by causing us to reduce our production or by impairing our ability to supply coal to our customers.

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 source of energy or could make our coal production less competitive than coal produced from other sources.  Disruption of transportation services due to weather-related problems, flooding, drought, accidents, mechanical difficulties, strikes, lockouts, bottlenecks or other events could temporarily impair our ability to supply coal to our customers.  Our transportation providers may face difficulties in the future that may impair our ability to supply coal to our customers, resulting in decreased revenue.  If there are disruptions of the transportation services provided by our primary rail carriers that transport our coal and we are unable to find alternative transportation providers to ship our coal, our business could be adversely affected.

Conversely, significant decreases in transportation costs could result in increased competition from coal producers in other parts of the country.  For instance, difficulty in coordinating the many eastern 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 coal shipments originating in the eastern U.S. inherently more expensive on a per-mile basis than coal shipments originating in the western U.S.  Historically, high coal transportation rates from the western coal producing areas into certain eastern markets limited the use of western coal in those markets.  Lower rail rates from the western coal producing areas to markets served by eastern U.S. coal producers have created major competitive challenges for eastern coal producers.  In the event of further reductions in transportation costs from western coal producing areas, the increased competition with certain eastern coal markets could have a material adverse effect on our business, financial condition and results of operations.

It is possible that states in which our coal is transported by truck may modify or increase enforcement of their laws regarding weight limits or coal trucks on public roads.  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 revenue.

We may not be able to successfully grow through future acquisitions.

We have expanded our operations by adding and developing mines and coal reserves in existing, adjacent and neighboring properties.  We continually seek to expand our operations and coal reserves.  Our future growth could be limited if we are unable to continue to make acquisitions, or if we are unable to successfully integrate the companies, businesses or properties we acquire.  We may not be successful in consummating any acquisitions and the consequences of undertaking these acquisitions are unknown.  Moreover, any acquisition could be dilutive to earnings. Our ability to make acquisitions in the future could require significant amounts of financing that may not be available to us under acceptable terms and may be limited by restrictions under our existing or future debt agreements, competition from other coal companies for attractive properties or the lack of suitable acquisition candidates.

Expansions and acquisitions involve a number of risks, any of which could cause us not to realize the anticipated benefits.

If we are unable to successfully integrate the companies, businesses or properties we acquire, our profitability may decline, and we could experience a material adverse effect on our business, financial condition, or results of operations.  Expansion and acquisition transactions involve various inherent risks, including:

Any one or more of these factors could cause us not to realize the benefits anticipated to result from an expansion or acquisition. Any expansion or acquisition opportunities we pursue could materially affect our liquidity and capital resources and may require us to incur indebtedness, seek equity capital or both. In addition, future expansions or acquisitions could result in us assuming more long-term liabilities relative to the value of the acquired assets than we have assumed in our previous expansions and/or acquisitions.

Completion of growth projects and future expansion could require significant amounts of financing that may not be available to us on acceptable terms, or at all.

We plan to fund capital expenditures for our current growth projects with existing cash balances, future cash flows from operations, borrowings under credit facilities and cash provided from the issuance of debt or equity. WeaknessAt times, weakness in the energy sector in general and coal, in particular, has significantly impacted access to the debt and equity capital markets. Accordingly, our funding plans may be negatively impacted by this constrained environment as well as numerous other factors, including higher than anticipated capital expenditures or lower than expected cash flow from operations. In addition, we may be unable to refinance our current credit facilitiesdebt obligations when they expire or obtain adequate funding prior to expiry because our lending counterparties may be unwilling or unable to meet their funding obligations. Furthermore, additional growth projects and expansion opportunities may develop in the future that could also require significant amounts of financing that may not be available to us on acceptable terms or in the amounts we expect, or at all.

Various factors could adversely impact the debt and equity capital markets as well as our credit ratings or our ability to remain in compliance with the financial covenants under our then current debt agreements, which in turn could have a material adverse effect on our financial condition, results of operations and cash flows. If we are unable to finance our growth and future expansions as expected, we could be required to seek alternative financing, the terms of which may not be attractive to us, or to revise or cancel our plans.

Terrorist attacks or cyber-incidents could result in information theft, data corruption, operational disruption and/or financial loss.

Like most companies, we have become increasingly dependent upon digital technologies, including information systems, infrastructure and cloud applications and services, to operate our businesses, to process and record financial and operating data, communicate with our business partners, analyze mine and mining information, estimate quantities of coal reserves, as well as other activities related to our businesses. Strategic targets, such as energy-related assets, may be at greater risk of future terrorist or cyber-attacks than other targets in the U.S. Deliberate attacks on, or security breaches in, our systems or infrastructure, or the systems or infrastructure of third parties, could lead to corruption or loss of our proprietary data and potentially sensitive data, delays in production or delivery, difficulty in completing and settling transactions, challenges in maintaining our books and records, environmental damage, communication interruptions, other operational disruptions and third-party liability. Our insurance may not protect us against such occurrences. Consequently, it is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition, results of operations and cash flows. Further, as cyber incidents continue to evolve, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents.

We may not recover our investments in our mining and other assets, which may require us to recognize impairment charges related to those assets.

The value of our assets has from time to time been adversely affected by numerous uncertain factors, some of which are beyond our control, including unfavorable changes in the economic environments in which we operate, lower-than-expected coal pricing, technical and geological operating difficulties, an inability to economically extract our coal reserves and unanticipated increases in operating costs. These factors may trigger the recognition of additional impairment charges in the future, which could have a substantial impact on our results of operations.

If we are unable to comply with the covenants contained in our credit agreement, the lenders could declare all amounts outstanding to be due and payable and foreclose on their collateral, which could materially adversely affect our financial condition and operations.

As disclosed in Note 5 to our financial statements, there are two key ratio covenants stated in our credit agreement: (i) a Minimum Debt Service Coverage Ratio (consolidated adjusted EBITDA/annual debt service) of 1.05 to 1 and (ii) a Maximum Leverage Ratio (consolidated funded debt/trailing twelve months adjusted EBITDA) not to exceed 3.00 to 1, which also decreases in future periods further reducing the maximum leverage permitted. On December 31, 2021, our debt service coverage ratio was 1.11, and our leverage ratio was 2.34. Therefore, we were in compliance with these two ratios.

Our indebtedness may limit our ability to borrow additional funds or capitalize on business opportunities.

On December 31, 2021, our bank debt was $111.7 million. Our leverage may:

Various limitations in our debt agreements may reduce our ability to incur additional indebtedness, to engage in some transactions, and capitalize on business opportunities. Any subsequent refinancing of our current indebtedness or any new indebtedness could have similar or greater restrictions.

We could be deemed ineligible for the Paycheck Protection Program (PPP) loan we received in 2020 upon audit by the United States Small Business Administration (SBA) upon completion of an SBA audit.

The PPP loan application required us to certify that the current economic uncertainty made the PPP loan request necessary to support our ongoing operations. While we made this certification in good faith after analyzing, among other things, our financial situation and access to alternative forms of capital, and believe that we satisfied all eligibility criteria and that our receipt of the PPP loan is consistent with the broad objectives of the Paycheck Protection Program of the CARES Act, the certification described above does not contain any objective criteria and is subject to interpretation. In addition, the SBA has stated that it is unlikely that a public company with substantial market value and access to capital markets will be able to make the required certification in good faith. The lack of clarity regarding loan eligibility under the program resulted in significant media coverage and controversy with respect to public companies applying for and receiving loans. If despite our good faith belief that we satisfied all eligibility requirements for the PPP loan, we are found to have been ineligible to receive the PPP loan or in violation of any of the laws or regulations that apply to us in connection with the PPP loan, including the False Claims Act, we may be subject to penalties, including significant civil, criminal and administrative penalties and could be required to repay the PPP loan. We received forgiveness of the entire $10 million of the PPP loan in July 2021, and as a part of the forgiveness process were required to make certain certifications that will be subject to audit and review by governmental entities and could subject us to significant penalties and liabilities if found to be inaccurate. In addition, our receipt of the PPP loan resulted in adverse publicity, and a review or audit by the SBA or other government entity or claims under the False Claims Act could consume significant financial and management resources. Any of these events could harm our business, results of operations, and financial condition.

Investor and lender focus on ESG matters may negatively impact our business, financial results, and stock price.

Companies across all industries, including companies in the fossil-fuel industry, are facing increased scrutiny from stakeholders related to their ESG practices. Companies that do not adapt or comply with evolving investor or stakeholder expectations and standards, or are perceived to have not responded appropriately to ESG issues, regardless of any legal requirement to do so, may suffer reputational damage and the business, financial condition, and stock price of such companies could be materially and adversely affected. Several advocacy groups, both domestically and internationally, have campaigned for governmental and private action to promote change at public companies related to ESG matters, including through the investment and voting practices of investment advisers, public pension funds, universities, and other members of the investing community. These activities include increasing attention to and demands for action related to climate change, promoting the use of substitutes to fossil-fuel products, encouraging the divestment of fossil-fuel equities, and pressuring lenders to limit funding to companies engaged in the extraction of fossil-fuel reserves. These activities could increase costs, reduce demand for our coal, reduce our profits, increase the potential for investigations and litigation, impair our brand, limit our choices for lenders, insurance providers and business partners, and have negative impacts on our stock price and access to capital markets.

In addition, certain organizations that provide corporate governance and other corporate risk information to investors have developed scores and ratings to evaluate companies and investment funds based upon ESG or "sustainability" metrics. Currently, there are no universal standards for such scores or ratings, but consideration of sustainability evaluations is becoming more broadly accepted by investors. Indeed, many investment funds focus on positive ESG business practices and sustainability scores when making investments, whereas other funds may use certain ESG criteria to "screen" certain sectors, such as coal or fossil fuels more generally, out of their investments. In addition, investors, particularly institutional investors, use these scores to benchmark companies against their peers and if a company is perceived as lagging, these investors may engage with companies to require improved ESG disclosure or performance or sell their interests in the company, particularly if its ESG performance does not improve. Moreover, certain members of the broader investment community may consider a company's sustainability score as a reputational or other factor in making an investment decision. Companies in the energy industry, and in particular those focused on coal, natural gas, or oil extraction, often do not score as well under ESG assessments compared to companies in other industries. Consequently, a low ESG or sustainability score could result in our securities being excluded from the portfolios of certain investment funds and investors, restricting our access to capital to fund our continuing operations and growth opportunities.

Additionally, to the extent ESG matters negatively impact our reputation, we may not be able to compete as effectively to recruit or retain employees, which may adversely affect our operations.

Risks Related to our Industry

A substantial or extended decline in coal prices could negatively impact our results of operations.

Our results of operations are primarily dependent upon the prices we receive for our coal, as well as our ability to improve productivity and control costs. The prices we receive for our production depends upon factors beyond our control, including:

Any adverse change in these factors could result in weaker demand and lower prices for our products. A substantial or extended decline in coal prices could materially and adversely affect us by decreasing our revenues to the extent we are not protected by the terms of existing coal supply agreements.

Competition within the coal industry may adversely affect our ability to sell coal, and excess production capacity in the industry could put downward pressure on coal prices.

We compete with other coal producers for domestic coal sales in various regions of the U.S. The most important factors on which we compete are delivered price (i.e., the cost of coal delivered to the customer, including transportation costs, which are generally paid by our customers either directly or indirectly), coal quality characteristics, contract flexibility (e.g., volume optionality and multiple supply sources) and reliability of supply. Some competitors may have, among other things, larger financial and operating resources, lower per ton cost of production, or relationships with specific transportation providers. The competition among coal producers may impact our ability to retain or attract customers and could adversely impact our revenues and cash from operations.

Changes in taxes or tariffs and other trade measures could adversely affect our results of operations, financial position and cash flows.

We pay certain taxes and fees related to our operations. Congress or state legislatures may seek to increase these taxes and fees that relate specifically to the coal industry. We cannot predict further developments, and such increases could have a material adverse effect on our results of operations, financial position, and cash flows.

New tariffs and other trade measures could adversely affect our results of operations, financial position and cash flows. In response to the tariffs imposed by the United States, the European Union, Canada, Mexico and China have imposed tariffs on United States goods and services. The new tariffs, along with any additional tariffs or trade restrictions that may be implemented by the United States or retaliatory trade measures or tariffs implemented by other countries, could result in reduced economic activity, increased costs in operating our business, reduced demand and changes in purchasing behaviors for thermal coal, limits on trade with the United States or other potentially adverse economic outcomes. While tariffs and other retaliatory trade measures imposed by other countries on United States goods have not yet had a significant impact on our business or results of operations, we cannot predict further developments, and such existing or future tariffs could have a material adverse effect on our results of operations, financial position and cash flows and could reduce our revenues and cash available for distribution.

Changes in consumption patterns by utilities regarding the use of coal have affected our ability to sell the coal we produce.

The domestic electric utility industry accounts for the vast majority of domestic coal 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 fuel oil as well as alternative sources of energy. Gas-fueled generation has the potential to displace a significant amount of coal-fired electric power generation in the near term, particularly from older, less efficient coal-fired powered generators.  We expect that many of the new power plants needed in the United States to meet increasing demand for electricity generation will be fueled by natural gas because gas-fired plants are cheaper to construct and permits to construct these plants are easier to obtain.

Future environmental regulation of GHG emissions also could accelerate the use by utilities of fuels other than coal. In addition, federal and state mandates for increased use of electricity derived from renewable energy sources could affect demand for coal. Such mandates, combined with other incentives to use renewable energy sources, such as tax credits, could make alternative fuel sources more competitive with coal. A decrease in coal consumption by the domestic electric utility industry could adversely affect the price of coal, which could negatively impact our results of operations and reduce our cash from operations.

Other factors, such as efficiency improvements associated with technologies powered by electricity have slowed electricity demand growth and could contribute to slower growth in the future. Further decreases in the demand for electricity, such as decreases that could be caused by a worsening of current economic conditions, a prolonged economic recession, or prolonged recovery from the COVID-19 pandemic, could have a material adverse effect on the demand for coal and our business over the long term.

Extensive environmental laws and regulations affect coal consumers and have corresponding effects on the demand for coal as a fuel source.

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 coal-fired electric power plants, which are the ultimate consumers of much of our coal. These laws and regulations can require significant emission control expenditures for many coal-fired power plants, and various new and proposed laws and regulations could require further emission reductions and associated emission control expenditures. These laws and regulations could affect demand and prices for coal. There is also continuing pressure on federal and state regulators to impose limits on carbon dioxide emissions from electric power plants, particularly coal-fired power plants. Further, far-reaching federal regulations promulgated by the EPA in the last several years, such as CSAPR and MATS, have led to the premature retirement of coal-fired generating units and a significant reduction in the amount of coal-fired generating capacity in the U.S.

Our operations are subject to a series of risks resulting from climate change.

Combustion of fossil fuels, such as the coal we produce, results in the emission of carbon dioxide into the atmosphere. Concerns about the environmental impacts of such emissions have resulted in a series of regulatory, political, litigation, and financial risks for our business. Global climate issues continue to attract public and scientific attention. Most scientists have concluded that increasing concentrations of GHGs in the Earth's atmosphere could produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods, and other climatic events.   Increasing government attention is being paid to global climate issues and to emissions of GHGs, including emissions due to fossil fuels.

In the United States, no comprehensive climate change legislation has been implemented at the federal level. However, following the U.S. Supreme Court finding that GHG emissions constitute a pollutant under the CAA, the EPA has adopted regulations that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain sources in the United States, or constrain the emissions of powerplants (though such emissions restraints have been subject to challenge.) 

Separately, various states and groups of states have adopted or are considering adopting legislation, regulations, or other regulatory initiatives that are focused on such areas as GHG cap-and-trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. Internationally, the Paris Agreement requires member states to submit non-binding, individually-determined emissions reduction targets.  These commitments could further reduce demand and prices for fossil fuels.  Although the United States had withdrawn from the Paris Agreement, following President Biden’s executive order in January 2021, the United States rejoined the Agreement and, in April 2021, established a goal of reducing economy-wide net GHG emissions 50-52% below levels by 2030. Additionally, at COP26 in Glasgow

in November 2021, the United States and the European Union jointly announced the launch of a Global Methane Pledge committing to a collective goal of reducing global methane emissions by at least 30% from 2020 levels by 2030, including "all feasible reductions" in the energy sector. The full impact of these actions is uncertain at this time and it is unclear what additional initiatives may be adopted or implemented that may have adverse effects upon us and our operators' operations.

Governmental, scientific, and public concern over climate change has also resulted in increased political risks, including certain climate-related pledges made by certain candidates now in political office. In January 2021, President Biden issued an executive order that commits to substantial action on climate change, calling for, among other things, the increased use of zero-emissions vehicles by the federal government, the elimination of subsidies provided to the fossil-fuel industry, a doubling of electricity generated by offshore wind by 2030, and increased emphasis on climate-related risks across governmental agencies and economic sectors. Other actions that may be pursued include restrictive requirements on new pipeline infrastructure or fossil-fuel export facilities or the promulgation of a carbon tax or cap and trade program. Further, although Congress has not passed such legislation, almost half of the states have begun to address GHG emissions, primarily through the planned development of emissions inventories, regional GHG cap and trade programs, or the establishment of renewable energy requirements for utilities. Depending on the particular program, we or our customers could be required to control GHG emissions or to purchase and surrender allowances for GHG emissions resulting from our operations. Litigation risks are also increasing. 

Apart from governmental regulation, there are also increasing financial risks for fossil-fuel producers as stakeholders of fossil-fuel energy companies may elect in the future to shift some or all of their support into non-energy related sectors. Institutional lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil-fuel energy companies. For example, at COP26, the Glasgow Financial Alliance for Net Zero ("GFANZ") announced that commitments from over 450 firms across 45 countries had resulted in over $130 trillion in capital committed to net zero goals. The various sub-alliances of GFANZ generally require participants to set short-term, sector-specific targets to transition their financing, investing, and/or underwriting activities to net zero emissions by 2050. There is also a risk that financial institutions will be required to adopt policies that have the effect of reducing the funding provided to the fossil-fuel sector. In late 2020, the Federal Reserve announced it had joined the Network for Greening the Financial System ("NGFS"), a consortium of financial regulators focused on addressing climate-related risks in the financial sector. Subsequently, in November 2021, the Federal Reserve issued a statement in support of the efforts of the NGFS to identify key issues and potential solutions for the climate-related challenges most relevant to central banks and supervisory authorities. Although we cannot predict the effects of these actions, such limitation of investments in and financing, bonding, and insurance coverages for fossil-fuel energy companies could adversely affect our coal mining operations. Additionally, the SEC announced its intention to promulgate rules requiring climate disclosures. Although the form and substance of these requirements is not yet known, this may result in additional costs to comply with any such disclosure requirements.

The adoption and implementation of new or more stringent international, federal, or state legislation, regulations, or other regulatory initiatives that impose more stringent standards for GHG emissions from fossil-fuel companies could result in increased costs of compliance or costs of consuming, and thereby reduce demand for coal, which could reduce the profitability of our interests. Additionally, political, litigation, and financial risks could result in either us restricting or canceling mining activities, incurring liability for infrastructure damages as a result of climatic changes, or having an impaired ability to continue to operate in an economic manner. One or more of these developments, as well as concerted conservation and efficiency efforts that result in reduced electricity consumption, and consumer and corporate preferences for non-fossil-fuel sources, including alternative energy sources, could cause prices and sales of our coal to materially decline and could cause our costs to increase and adversely affect our revenues and results of operations.

Climate change may also result in various physical risks, such as the increased frequency or intensity of extreme weather events or changes in meteorological and hydrological patterns that could adversely impact our operations. Such physical risks may result in damage to our facilities or otherwise adversely impact operations which could decrease our production. We may not have insurance to cover these risks and the consequences for our operations could have a negative impact on the costs and revenues from operations.

We or our customers could be subject to related to the alleged effects of climate change.

Increasing attention to climate change risk has also resulted in a recent trend of governmental investigations and private litigation by state and local governmental agencies as well as private plaintiffs in an effort to hold energy companies accountable for the alleged effects of climate change. Other public nuisance lawsuits have been brought in the past against power, coal, and oil & gas companies alleging that their operations are contributing to climate change. The plaintiffs in these suits sought various remedies, including punitive and compensatory damages and injunctive relief. While the U.S. Supreme Court held that federal common law provided no basis for public nuisance claims against the defendants in those cases, tort-type liabilities remain a possibility and a source of concern. Government entities in other states (including California and New York) have brought similar claims seeking to hold a wide variety of companies that produce fossil fuels liable for the alleged impacts of the GHG emissions attributable to those fuels. Those lawsuits allege damages as a result of climate change and the plaintiffs are seeking unspecified damages and abatement under various tort theories. Separately, litigation has been brought against certain fossil-fuel companies alleging that they have been aware of the adverse effects of climate change for some time but failed to adequately disclose such impacts to their investors or consumers. We have not been made a party to these other suits, but it is possible that we could be included in similar future lawsuits initiated by state and local governments as well as private claimants.

Litigation resulting from disputes with our customers may result in substantial costs, liabilities, and loss of revenues.

From time to time we have disputes with our customers over the provisions of long-term coal supply contracts relating to, among other things, coal pricing, quality, quantity and the existence of specified conditions beyond our or our customers’ control that suspend performance obligations under the particular contract. Disputes may occur in the future, and we may not be able to resolve those disputes in a satisfactory manner, which could have a material adverse effect on our business, financial condition and results of operations.

Our profitability may decline due to unanticipated mine operating conditions and other events that are not within our control and that may not be fully covered under our insurance policies.

Our mining operations are influenced by changing conditions or events that can affect production levels and costs at particular mines for varying lengths of time and, as a result, can diminish our profitability. These conditions and events include, among others:

These conditions have the potential to significantly impact our operating results. Prolonged disruption of production at any of our mines would result in a decrease in our revenues and profitability, which could materially adversely impact our quarterly or annual results.

Our inability to obtain commercial insurance at acceptable rates or our failure to adequately reserve for self-insured exposures could increase our expenses and have a negative impact on our business.

We believe that commercial insurance coverage is prudent in certain areas of our business for risk management. Insurance costs could increase substantially in the future and could be affected by natural disasters, fear of terrorism, financial irregularities, cybersecurity breaches and other fraud at publicly-traded companies, intervention by the government, an increase in the number of claims received by the carriers, and a decrease in the number of insurance carriers. In addition, the carriers with which we hold our policies could go out of business or be otherwise unable to fulfill their contractual obligations or could disagree with our interpretation of the coverage or the amounts owed. In addition, for certain types or levels of risk, such as risks associated with certain natural disasters or terrorist attacks, we may determine that we cannot obtain commercial insurance at acceptable rates, if at all. Therefore, we may choose to forego or limit our purchase of relevant commercial insurance, choosing instead to self-insure one or more types or levels of risks. If we suffer a substantial loss that is not covered by commercial insurance or our self-insurance reserves, the loss and related expenses could harm our business and operating results. Also, exposures exist for which no insurance may be available and for which we have not reserved.  In addition, environmental activists could try to hamper fossil-fuel companies by other means including pressuring insurance and surety companies into restricting access to certain needed coverages.

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

We are subject to numerous federal, state and local laws and regulations affecting the coal mining industry, including laws and regulations pertaining to employee health and safety, permitting and licensing requirements, air and water quality standards, plant and wildlife protection, reclamation and restoration of mining properties after mining is completed, the discharge or release of materials into the environment, surface subsidence from underground mining and the effects that mining has on groundwater quality and availability. Certain of these laws and regulations may impose strict liability without regard to fault or 

legality of the original conduct. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial liabilities, and the issuance of injunctions limiting or prohibiting the performance of operations. Complying with these laws and regulations may be costly and time-consuming and may delay commencement or continuation of exploration or production operations. The possibility exists that new laws or regulations may be adopted, or that judicial interpretations or more stringent enforcement of existing laws and regulations may occur, which could materially affect our mining operations, cash flow, and profitability, either through direct impacts on our mining operations, or indirect impacts that discourage or limit our customers’ use of coal. Federal and state laws addressing mine safety practices impose stringent reporting requirements and civil and criminal penalties for violations. Federal and state regulatory agencies continue to interpret and implement these laws and propose new regulations and standards. Implementing and complying with these laws and regulations has increased and will continue to increase our operational expense and have an adverse effect on our results of operation and financial position.

We may be unable to obtain and renew permits necessary for our operations, which could reduce our production, cash flow and profitability.

Mining companies must obtain numerous governmental permits or approvals that impose strict conditions and obligations relating to various environmental and safety matters in connection with coal mining. The permitting rules are complex and can change over time. Regulatory authorities exercise considerable discretion in the timing and scope of permit issuance. The public has the right to comment on permit applications and otherwise participate in the permitting process, including through court intervention. Accordingly, permits required to conduct our operations may not be issued, maintained or renewed, or may not be issued or renewed in a timely fashion, or may involve requirements that restrict our ability to economically conduct our mining operations. Limitations on our ability to conduct our mining operations due to the inability to obtain or renew necessary permits or similar approvals could reduce our production, cash flow, and profitability.

The EPA has begun reviewing permits required for the discharge of overburden from mining operations under Section 404 of the CWA. Various initiatives by the EPA regarding these permits have increased the time required to obtain and the costs of complying with such permits. In addition, the EPA previously exercised its “veto” power to withdraw or restrict the use of previously issued permits in connection with one of the largest surface mining operations in Appalachia. The EPA’s action was ultimately upheld by a federal court. As a result of these developments, we may be unable to obtain or experience delays in securing, utilizing or renewing Section 404 permits required for our operations, which could have an adverse effect on our results of operation and financial position.

In addition, some of our permits could be subject to challenges from the public, which could result in additional costs or delays in the permitting process, or even an inability to obtain permits, permit modifications or permit renewals necessary for our operations.

Fluctuations in transportation costs and the availability or reliability of transportation could reduce revenues by causing us to reduce our production or by impairing our ability to supply coal to our customers.

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 source of energy or could make our coal production less competitive than coal produced from other sources. Disruption of transportation services due to weather-related problems, flooding, drought, accidents, mechanical difficulties, strikes, lockouts, bottlenecks or other events could temporarily impair our ability to supply coal to our customers. Our transportation providers may face difficulties in the future that may impair our ability to supply coal to our customers, resulting in decreased revenues. If there are disruptions of the transportation services provided by our primary rail carriers that transport our coal and we are unable to find alternative transportation providers to ship our coal, our business could be adversely affected.

Conversely, significant decreases in transportation costs could result in increased competition from coal producers in other parts of the country. For instance, difficulty in coordinating the many eastern 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 coal shipments originating in the eastern U.S. inherently more expensive on a per-mile basis than coal shipments originating in the western U.S. Historically, high coal transportation rates from the western coal-producing areas into certain eastern markets limited the use of western coal in those markets. Lower rail rates from the western coal producing areas to markets served by eastern U.S. coal producers have created major competitive challenges for eastern coal producers. In the event of further reductions in transportation costs from western coal-producing areas, the increased competition with certain eastern coal markets could have a material adverse effect on our business, financial condition and results of operations.

It is possible that states in which our coal is transported by truck may modify or increase enforcement of their laws regarding weight limits or coal trucks on public roads. 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 revenues.

We may not be able to successfully grow through future acquisitions.

We have expanded our operations by adding and developing mines and coal reserves in existing, adjacent and neighboring properties. We continually seek to expand our operations and coal reserves. Our future growth could be limited if we are unable to continue to make acquisitions, or if we are unable to successfully integrate the companies, businesses or properties we acquire. We may not be successful in consummating any acquisitions and the consequences of undertaking these acquisitions are unknown. Moreover, any acquisition could be dilutive to earnings. Our ability to make acquisitions in the future could require significant amounts of financing that may not be available to us under acceptable terms and may be limited by restrictions under our existing or future debt agreements, competition from other coal companies for attractive properties or the lack of suitable acquisition candidates.

Expansions and acquisitions involve a number of risks, any of which could cause us not to realize the anticipated benefits.

If we are unable to successfully integrate the companies, businesses or properties we acquire, our profitability may decline, and we could experience a material adverse effect on our business, financial condition, or results of operations. Expansion and acquisition transactions involve various inherent risks, including:

Any one or more of these factors could cause us not to realize the benefits anticipated to result from an expansion or acquisition. Any expansion or acquisition opportunities we pursue could materially affect our liquidity and capital resources and may require us to incur indebtedness, seek equity capital or both. In addition, future expansions or acquisitions could result in us assuming more long-term liabilities relative to the value of the acquired assets than we have assumed in our previous expansions and/or acquisitions.

The unavailability of an adequate supply of coal reserves that can be mined at competitive costs could cause our profitability to decline.

Our profitability depends substantially on our ability to mine coal reserves that have the geological characteristics that enable them to be mined at competitive costs and to meet the quality needed by our customers. Because we deplete our reserves as we mine coal, our future success and growth depend, in part, upon our ability to acquire additional coal reserves that are economically recoverable. Replacement reserves may not be available when required or, if available, may not be mineable at costs comparable to those 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 profitability and financial condition. Exhaustion of reserves at particular mines 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.

The estimates of our coal reserves may prove inaccurate and could result in decreased profitability.

The estimates of our coal reserves may vary substantially from actual amounts of coal we are able to recover economically. All of the reserves presented in this Annual Report on Form 10-K constitute proven and probable reserves. There are numerous uncertainties inherent in estimating quantities of reserves, including many factors beyond our control. Estimates of coal reserves necessarily depend upon a number of variables and assumptions, any one of which may vary considerably from actual results. These factors and assumptions relate to:

For these reasons, estimates of the recoverable quantities of coal attributable to any particular group of properties, classifications of reserves based on the risk of recovery and estimates of future net cash flows expected from these properties as prepared by different engineers, or by the same engineers at different times, may vary substantially. Actual production, revenue, and expenditures with respect to our reserves will likely vary from estimates, and these variations may be material. Any inaccuracy in the estimates of our reserves could result in higher than expected costs and decreased profitability.

Mining in certain areas in which we operate is more difficult and involves more regulatory constraints than mining in other areas of the U.S., which could affect the mining operations and cost structures of these areas.

The geological characteristics of some of our coal reserves, such as depth of overburden and coal seam thickness, make them difficult and costly to mine. As mines become depleted, replacement reserves may not be available when required or, if available, may not be mineable at costs comparable to those characteristicscharacteristic of the depleting mines. In addition, permitting, licensing and other environmental and regulatory requirements associated with certain of our mining operations are more costly and time-consuming to satisfy. These factors could materially adversely affect the mining operations and cost structures of, and our customers’ ability to use coal produced by, our mines.

Unexpected increases in raw material costs could significantly impair our operating profitability.

Our coal mining operations are affected by commodity prices. We use significant amounts of steel, petroleum products, and other raw materials in various pieces of mining equipment, supplies and materials, including the roof bolts required by the room-and-pillar method of mining. 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. Inflationary pressures have and could continue to lead to price increases affecting many of the components of our operating expenses such as fuel, steel, and maintenance expense.

There may be acts of nature or terrorist attacks or threats that could also impact the future costs of raw materials. Future volatility in the price of steel, petroleum products or other raw materials will impact our operational expenses and could result in significant fluctuations in our profitability. In March, 2018, President Trump announced that his administration would be assessing tariffs on steel imports which could increase our costs significantly.

Failure to obtain or renew surety bonds on acceptable terms could affect our ability to secure reclamation and coal lease obligations and, therefore, our ability to mine or lease coal.

Federal and state laws require us to obtain surety bonds to secure performance or payment of certain long-term obligations, such as mine closure or reclamation costs. We may have difficulty procuring or maintaining our surety bonds. Our bond issuers may demand higher fees, additional collateral, including letters of credit or other terms less favorable to us upon those renewals. Because we are required by state and federal law to have these bonds in place before mining can commence or continue, failure to maintain surety bonds, letters of credit or other guarantees or security arrangements would materially and adversely affect our ability to mine or lease coal. That failure could result from a variety of factors, including lack of availability, higher expense or unfavorable market terms, the exercise by third-party surety bond issuers of their right to refuse to renew the surety and restrictions on availability of collateral for current and future third-party surety bond issuers under the terms of our financing arrangements.

Terrorist attacks or cyber-incidents could result in information theft, data corruption, operational disruption and/or financial loss.

Like most companies, we have become increasingly dependent upon digital technologies, including information systems, infrastructure and cloud applications and services, to operate our businesses, to process and record financial and operating data, communicate with our business partners, analyze mine and mining information, estimate quantities of coal reserves, as well as other activities related to our businesses. Strategic targets, such as energy-related assets, may be at greater risk of future terrorist or cyber-attacks than other targets in the U.S. Deliberate attacks on, or security breaches in, our systems or infrastructure, or the systems or infrastructure of third parties, or cloud-based applications could lead to corruption or loss of our proprietary data and potentially sensitive data, delays in production or delivery, difficulty in completing and settling transactions, challenges in maintaining our books and records, environmental damage, communication interruptions, other operational disruptions and third-party liability. Our insurance may not protect us against such occurrences. Consequently, it is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition, results of operations and cash flows. Further, as cyber incidents continue to evolve, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents.

Certain federal income tax deductions currently available with respect to coal mining and production may be eliminated as a result of future legislation.

In past years, members of Congress have indicated a desire to eliminate certain key U.S. federal income tax provisions currently applicable to coal companies, including the percentage depletion allowance with respect to coal properties. No legislation with that effect has been proposed, but the elimination of those provisions would negatively impact our financial statements orand results of operations.

Risks RelatedA shortage of skilled labor may make it difficult for us to Our Indebtednessmaintain labor productivity and Liquidity

If we are unable to comply with the covenants contained in our credit agreement, the lenderscompetitive costs and could declare all amounts outstanding to be due and payable and foreclose on their collateral, which could materially adversely affect our financial condition and operations.

As disclosed in Note 3 to our financial statements, there are two key ratio covenants stated in our credit agreement: (i) a minimum debt service coverage ratio of 1.25 to 1 and (ii) a current maximum leverage ratio (Sunrise funded debt/adjusted EBITDA) not to exceed 4.25 to 1, which also decreases in future periods further reducing the maximum leverage permitted.  On December 31, 2017, our debt service coverage ratio was 1.90, and our leverage ratio was 2.40. Therefore, we were in compliance with these two ratios.

profitability.

Our indebtedness may limit

Efficient coal mining using modern techniques and equipment requires skilled laborers, preferably with at least one year of experience and proficiency in multiple mining tasks.  In recent years, a shortage of experienced coal miners has caused us to include some inexperienced staff in the operation of certain mining units, which decreases our productivity and increases our costs.  This shortage of experienced coal miners is the result of a significant percentage of experienced coal miners reaching retirement age, combined with the difficulty of retaining existing workers in and attracting new workers to the coal industry.  Thus, this shortage of skilled labor could continue over an extended period. If the shortage of experienced labor continues or worsens, it could have an adverse impact on our labor productivity and costs and our ability to borrow additional funds or capitalize on business opportunities.expand production in the event there is an increase in the demand for our coal, which could adversely affect our profitability.

Disruptions in supply chains could significantly impair our operating profitability.

On December 31, 2017, our debt was $202 million.  Our leverage may:

Various limitationsWe are dependent upon vendors to supply mining equipment, safety equipment, supplies, and materials. If a vendor fails to deliver on its commitments, or if common carriers have difficulty providing capacity to meet demands for their services, we could experience reductions in our debt agreements may reduceproduction or increased production costs, which could lead to reduced profitability and adversely affect our ability to incur additional indebtedness, to engage in some transactions and to capitalize on business opportunities.  Any subsequent refinancingresults of our current indebtedness or any new indebtedness could have similar or greater restrictions.operations.

Risk Related to Possible Future Impairment ChargeInflationary pressures could significantly impair our operating profitability.

Carlisle Mine

In December 2016,Any future inflationary or deflationary pressures could adversely affect the deteriorationresults of our operations. For example, at times our results have been significantly impacted by price increases affecting many of the North Endcomponents of the Carlisle Mine, coupled with lowerour operating expenses such as fuel, steel, maintenance expense and labor. In addition to potential cost increases, inflation could cause a decline in global or regional economic conditions that reduce demand for our coal prices led us to determine that the northern endand could adversely affect our results of the Carlisle Mine no longer could be safely and profitably mined. The sealing of the North End was completed in March 2017.  In connection therewith, we identified specific assets totaling $16.6 million ($15.1 million of property and equipment and $1.5 million of advanced royalties) that were written off in 2016. 

The Carlisle Mine assets had an aggregate net carrying value of $110 million at December 31, 2017.  With the Carlisle Mine remaining in hot idle status, we conducted a review of the Carlisle Mine assets as of December 31, 2017, based on estimated future net cash flows, and determined that no further impairment was necessary; however, if future expectations and assumptions change we may incur possible impairment in future periods.

Bulldog Reserves

In October 2017, we entered into an agreement to sell land associated with the Bulldog Mine for $4.9 million. As part of the transaction, we will hold the rights to repurchase the property for 8 years. Because of the likelihood of exercising the repurchase option, we are accounting for the sale as a financing transaction. The Bulldog Mine assets had an aggregate net carrying value of $15 million at December 31, 2017. Also in October 2017, the Illinois Department of Natural Resources (ILDNR) notified us that our mine application, along with modifications, was acceptable. The permit will be issued upon submittal of a fee and bond which are required within 12 months of the notification. We have determined that no impairment is necessary. If estimates inherent in the assessment change, it may result in future impairment of the assets.operations.

ITEM 1B.  UNRESOLVED STAFF COMMENTS.COMMENTS.  None.

ITEM 2.  PROPERTIES.

See Item“Item 7 MDA- Management’s Discussion and Analysis of Financial Condition and Results of Operations” for a discussion of our mines.

Coal Reserve Estimates

“Reserves” are defined by the SEC Industry Guide 7 as that part of a mineral deposit, which could be economically and legally extracted or produced at the time of the reserve determination. “Recoverable” reserves mean coal that is economically recoverable using existing equipment and methods under federal and state laws currently in effect. “Proven (measured) reserves” are defined by Guide 7 as reserves for which (a) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; grade and/or quality are computed from the results of detailed sampling and (b) the sites for inspection, sampling and measurement are spaced so closely, and the geologic character is so well defined that size, shape, depth and mineral content of reserves are well-established. “Probable reserves” are defined by Guide 7 as reserves for which quantity and grade and/or quality are computed from information similar to that used for proven (measured) reserves, but the sites for inspection, sampling, and measurement are farther apart or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven reserves, is high enough to assume continuity between points of observation.

Our reserve estimates are prepared by Scott McGuire, one of our mining engineers. Mr. McGuire is a licensed Professional Engineer in the State of Indiana and Kentucky and has sixteen years’ experience estimating coal reserves.

Standards set forth by the USGS were used to place areas of the mine reserves into the Proven (measured) and Probable (indicated) categories. Under these standards, coal within 1,320' of a data point is considered to be proven, and coal within 1,320' to 3,960' is placed in the Probable category. Only tons greater than 4’ in thickness are included in our underground reserves. All reserves are stated as a final salable product.

Prior to acquiring coal mineral leases, title abstractors conduct a preliminary title search on the property.  This information provides a strong indication of the coal owner, with whom we will enter into a lease. The next step is to execute a lease with the owner, giving us the rights to explore and mine the property.   Prior to mining, attorneys review the chain of mineral ownership to verify the lessor is the mineral owner. Prior to purchasing coal properties, we follow a similar process

ITEM 3.  LEGAL PROCEEDINGS.  None

ITEM 4.  MINE SAFETY DISCLOSURES:

Safety is a core value for us.us and our subsidiaries. As such, we have dedicated a great deal of time, energy, and resources to creating a culture of safety. Thus, we are very proud of the mine rescue team at Sunrise Coal whose current list of achievements includes reigning National Champions of the Nationwide Mine Rescue Skills Championship and Governor’s Award recipient (1^st place) at the 2017 Indiana Mine Rescue Association Contest.

See Exhibit 95 to this Form 10-K for a listing of our mine safety violations.

PART II

ITEM 5.  MARKET FOR REGISTRANT'SREGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.

Stock Price Information

Our common stock is tradedtrades on the NASDAQ Capital Market under the symbol HNRG, and 46%30.7% is held by our officers, directors, and their affiliates. The following table sets forth the dividends paid and the high and low closing sales price for the periods indicated:

		Dividends Paid				High				Low
2018
January 1 through March 9		$	0.04			$	7.31			$	5.96
2017
Fourth quarter			.04				6.56				4.87
Third quarter			.04				8.34				5.40
Second quarter			.04				8.32				6.30
First quarter			.04				9.79				7.48
2016
Fourth quarter			.04				10.02				7.24
Third quarter			.04				8.26				4.50
Second quarter			.04				5.10				4.03
First quarter			.04				5.68				4.05

 

At March 8, 2018,23, 2022, we had 205275 shareholders of record of our common stock; this number does not include the shareholders holding stock in "street name.”  We estimate we have over 5,000 street name holders.

 

Equity Compensation Plan Information

 

See Note 510 to our consolidated financial statements.

27

Stock Performance

The following performance compares Hallador Energy (Nasdaq: HNRG), the Russell 2000 Index, the SNL Coal Index, Alliance Resource Partners LP (NYSE: ARLP), Cloud Peak Energy (NYSE: CLD), and Foresight Energy (NYSE: FELP).

The graph assumes that you invested $100 in our common stock and in each company and index at the closing price on December 31, 2012, that all dividends were reinvested, and that you continued to hold your investment through December 31, 2017.

		Period Ended
Company / Index		12/31/12				12/31/13				12/31/14				12/31/15				12/31/16				12/31/17
Hallador Energy Company			100.00				99.14				137.64				58.09				119.20				81.70
Russell 2000 Index			100.00				138.82				145.62				139.19				168.85				193.58
Alliance Resource Partners LP			100.00				141.46				167.02				57.64				107.98				103.62
SNL Coal Index			100.00				98.12				72.68				18.19				37.61				37.92
Foresight Energy LP							100.00				90.66				21.51				39.43				27.41
Cloud Peak Energy Inc.			100.00				93.12				47.49				10.76				29.02				23.02
Source: S&P Global Market Intelligence

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ITEM 6.  SELECTED FINANCIAL DATA.[RESERVED]

For the years ended December 31,

(in thousands, except per share data)

		2017				2016				2015				2014				2013
Revenue:
Coal sales		$	268,202			$	278,924			$	339,490			$	233,902			$	137,436
Equity (loss) income – Savoy			460				(1,187	)			(1,532	)			5,272				5,827
Equity (loss) income - Sunrise Energy			(95	)			(249	)			(74	)			248				629
Liability extinguishment																			4,300
Other			3,066				3,962				2,236				1,749				5,678
			271,633				281,450				340,120				241,171				153,870
Net income before impairment and income taxes*			13,882				25,044				27,570				10,701				29,598
Asset impairment			-				16,560				-				-				-
Income tax expense (benefit)			(19,194	)			(4,026	)			7,438				482				7,175
Net income		$	33,076			$	12,510			$	20,132			$	10,219			$	22,423
Net income per share :
Basic and diluted		$	1.08			$	0.42			$	0.68			$	0.34			$	0.78
Cash dividends per share		$	0.16			$	0.16			$	0.16			$	0.16			$	0.12
Balance Sheet Information (end of period):
Total assets		$	518,193			$	531,323			$	540,378			$	579,585			$	259,199
Total bank debt*			201,992				238,617				249,470				306,345				16,000

* Non-GAAP measurement. See Note 2, Note 3, and Note 4 to the consolidated financial statements.

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ITEM 7.

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

ITEM 7.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

  

Our consolidated financial statements should be read in conjunction with this discussion.  The following analysis includes a discussion of metrics on a per ton basis derived from the condensed consolidated financial statements, which are considered non-GAAP measurements.  These metrics are significant factors in assessing our operating results and profitability.

 

OverviewCOVID-19

In the first quarter of 2020, COVID-19 emerged as a global pandemic.  The State of Indiana, where our operations are located, issued a shelter in place order from March 24, 2020, to May 4, 2020. The State deemed our operations necessary and essential, and we were allowed to operate as a supplier to critical power infrastructure. We continue to monitor the ongoing pandemic and note that if conditions deteriorate in the future, it could negatively impact our results of operations, financial position, and liquidity.

We have instituted many policies and procedures, in alignment with CDC guidelines along with state and local mandates, to protect our employees during the COVID-19 outbreak. We plan to keep these policies and procedures in place, in accordance with CDC, state, and local guidelines, and continually evaluate further enhancements for as long as necessary. We recognize that the COVID-19 outbreak, and responses thereto, will also impact both our customers and suppliers. As world economies have emerged from both the global pandemic and the power outages in Texas last winter, supplies have become more challenging to secure.  At times we have paid premiums for supplies to ensure no interruptions to our production.

As vaccines for COVID-19 continue to become readily available, we intend to continue encouraging our workforce to get vaccinated, and we are hopeful that the case rate of our employees will continue to decline, and economic activity in general will continue to accelerate.  We continue to offer cash incentives to employees who show proof of vaccination.

OVERVIEW

 

The largest portion of our business is devoted to coal mining in the State of Indiana through Sunrise Coal, LLC (a wholly ownedwholly-owned subsidiary) serving the electric power generation industry. We also own a 50% interest in Sunrise Energy, LLC, a private gas exploration company with operations in Indiana. We also own a 30.6% equity interest in Savoy Energy, L.P., a private oil and gas exploration company with operations in Michigan. WeIndiana, which we account for our interest in Savoy and Sunrise Energy using the equity method. We have reached an

On February 15th, 2022, Hallador Energy announced its new wholly-owned subsidiary, Hallador Power Company, LLC, will acquire Hoosier Energy’s 1-Gigawatt Merom Generating Station ("Merom"), located in Sullivan County, Indiana, in return for assuming certain decommissioning costs and environmental responsibilities. The transaction, which includes a 3.5-year power purchase agreement for Savoy(PPA), is scheduled to redeem our entire partnership interest for $8 million, which we expectclose in mid-July 2022 upon obtaining required governmental and financial approvals. 

Per the agreement, Hoosier will purchase 100% of the plant’s energy and capacity through May 2023, reducing purchases to finalize22% of energy output and 32% of its capacity beginning in mid-March 2018. Our net after commissions paidJune 2023 and through 2025. The existing renewable PPA – signed in May 2021 and representing 150 MW of solar generation and 50 MW of battery storage – will be $7.5 million.retained, with its start date delayed until Merom’s eventual retirement. 

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Going forward, Hallador Energy will have two primary subsidiaries:  Sunrise Coal, LLC and Hallador Power Company, LLC.  All coal production assets will remain with Sunrise Coal.  Hallador Power Company will hold assets associated with electricity production, including, but not limited to, the Merom Generating Station, Power Purchase Agreements and Interconnection rights.

 

We operateanticipate operating Merom post-closing in mid-July of 2022.  Hallador will provide little coal to the plant in 2022 but anticipates increasing Sunrise Coal’s sales to Merom in 2023 and beyond. 

We expect Hallador Power to contribute little to Hallador Energy profits in 2022.  However, this acquisition is significant starting in 2023, and we believe Hallador Power will double Hallador Energy’s EBITDA. 

Mining Properties

The following information concerning our mining properties has been prepared in accordance with the requirements of subpart 1300 of Regulation S-K, which first became applicable to us for the fiscal year ended December 31, 2021.  These requirements differ from the previously applicable disclosure requirements of SEC Industry Guide 7.  Among other differences, subpart 1300 of Regulation S-K requires us to disclose our mineral (coal) resources, which we have none, in addition to our mineral (coal) reserves, as of the end of our most recently completed fiscal year both in the aggregate and for each of our individually material mining properties.

As used in this Annual Report on Form 10-K, the terms “mineral resources,” “mineral reserve,” “proven mineral reserve” and “probable mineral reserve” are defined and used in accordance with subpart 1300 of Regulation S-K.  Under subpart 1300 of Regulation S-K, mineral resources may not be classified as “mineral reserves” unless the determination has been made by a qualified person (QP) that the mineral resources can be the basis of an economically viable project.  You are specifically cautioned not to assume that any part or all of the mineral deposits (including any mineral resources) in these categories will ever be converted into mineral reserves, as defined by the SEC.

Internal qualified person(s) have estimated the Company’s mineral reserves and mineral resources based on geologic data, coal ownership (control) information, and current and/or proposed operating plans.  Periodic updates occur to mineral reserve and mineral resource estimates attributableto revised mine plans, new exploration data, depletion from coal production, property acquisitions or dispositions, and/or other geologic or mining data.  Sunrise’s estimates of mineral reserves are proven and probable reserves that could be extracted or produced at the time of the reserve determination, economically, legally, and after considering all material modifying factors.  Modifications or updates of the estimates of the Company’s mineral reserves is limited to qualified geologists and mining engineers.  All modifications or updates of the estimates of recoverable coal reserves are documented.  The John T. Boyd Company, a qualified person firm, has assessed the Company’s estimates of mineral reserves and mineral resources and supporting information.  Based upon the review, John T. Boyd Company provided modification to the Company’s estimates of mineral reserves where warranted.

The information that follows is derived, for the most part, from, and in some instances is extracted from, the Oaktown Mining Complex technical report summary (“TRS”).  The Oaktown Mining Complex is the Company’s individually material property.  Sections of the following information provided herein do not fully describe assumptions, qualifications, and procedures.  Reference should be made to the full text of the TRS which is made a part of this Annual report on Form 10-K and incorporated hereby by reference.  The Oaktown Mining Complex TRS was prepared by the John T. Boyd Company in compliance with the Item 60(b)(96) and subpart 1300 of Regulation S-K.

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The following table provides a summary of all of the Company’s mineral reserves determined by the John T. Boyd Company as of the end of the fiscal year ended December 31, 2021:

SUMMARY MINERAL RESERVES AT END OF THE

FISCAL YEAR ENDED DECEMBER 31, 2021

		Mineral Reserves (tons in millions)
		Proven		Probable		Total
Oaktown Mining Complex
Oaktown Fuels No. 1 Mine		40.1		0.4		40.5
Oaktown Fuels No. 2 Mine		29.7		1.2		30.9
Total		69.8		1.6		71.4

Oaktown Mining Complex

The Oaktown Mining Complex is a coal mining and processing operation located in Knox and Sullivan counties, Indiana, and Crawford and Lawrence counties, Illinois.  The following figure shows the general location of the Oaktown Mining Complex:

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Comprising 118 square miles within the ILB coal-producing region of the mid-western United States, the Oaktown Mining Complex is one of the largest underground Room-and-Pillar (R&P) coal mining complexes in North America.  The Oaktown Mining Complex operations currently consist of two active underground mines - Oaktown Fuels No. 1 Mine and oneOaktown Fuels No. 2 Mine - and related infrastructure.  Geographically, the Oaktown Complex Coal Preparation Plant is located at approximately 28°51’24.7” N latitude and 87°25’30.9” W longitude.  Within the Oaktown Mining Complex area and immediate vicinity, our Company controls approximately 75,000 acres of mineral rights.  This control exists as a complex collection of leases that apply to more than 2,000 tracts.  Each of which range from less than an acre to several hundred acres in size.  Ownership of the surface rights and the mineral rights is often severed for the properties and the estates are often fractions, in which mineral rights are split between several owners.  The Company and its predecessors have acquired the necessary rights to support development and operations through purchase or lease agreements with predominately private owners or entities. As part of the Oaktown Mining Complex, the Company controls surface rights through fee simple ownership for over 1,700 permitted acres.  Upon those acres resides the surface facilities for mine in southwestern Indiana. The underground mines,accesses, processing, storing, shipping, and refuse disposal facilities (i.e., refuse impoundment site and fine refuse injection sites).  Our involvement with the Oaktown Mining Complex dates to 2014 with the acquisition of Oaktown Fuels No. 1 and No. 2 Mines from Vectren Fuels.

Each mine of the Oaktown 2Mining Complex utilizes R&P mining (employing Continuous Miners [CM]) for primary production.  This mining method is highly productive and commercially demonstrated; it has been one of the primary approaches to underground mining the Indiana V Seam for decades.  Oaktown Mining Complex has utilized this mining method since the inception of each operation.  To date, Oaktown Mining Complex has produced a combined 58.3 million tons of clean coal.  The complex is configured to operate up to 7 CM sections, with an annual production target of approximately 6-7 million product tons.  The Oaktown Complex Coal Preparation Plant serves as the coal washing and shipment facility for the Oaktown Mining Complex’s two R&P mines.  The plant was commissioned in 2009 to wash coal by the Oaktown Fuels No. 1 Mine.  The Oaktown Complex Coal Preparation Plant has a current processing capacity of 1,600 raw tons-per-hour (TPH).  Product coal from the Oaktown Mining Complex is transported to its customer base via rail, truck, or a combination of both.  The Oaktown Complex Coal Preparation Plant is served by both the CSX Railroad and Indiana Railroad (INRD) via a rail spur and rail loop that connects the complex with the mainline rail just north of Oaktown, Indiana. 

Additionally, the Oaktown Complex Coal Preparation Plant can facilitate the loading of trucks for direct transport to select customers, or to our transload facility in Princeton, Indiana serviced by the Norfolk Southern (NS) Railroad.

Sources of electrical power, water, supplies, and materials are readily available.  Electrical power is provided to the mines and facilities by regional utility companies.  Water is supplied by public water services, surface impoundments, or water wells.

Multiple permits are required by federal and state law for underground mining, coal preparation and related facilities, and other incidental activities.  All necessary permits to support current operations are in place or pending approval.  New permits or permit revisions may be necessary from time to time to facilitate future operations.  Given sufficient time and planning, we should be able to secure new permits, as required, to maintain our planned operations within the context of the current regulations.

Permits generally require that the Company post a performance bond in an amount established by the regulator program to: (1) provide assurance that any disturbance or liability created during mining operation is properly mitigated, and (2) assure that all regulation requirements of the permit are fully satisfied. We hold surety bonds to cover obligations relating to mining and reclamation, road repair, etc. Those obligations are currently estimated at $5.8 million.

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Additional information is provided in the following table regarding the Oaktown Mining Complex mineral reserves:

OAKTOWN MINING COMPLEX
Recoverable Coal Reserves as of December 31, 2021 and 2020
		As Received		As Received
		Heat		SO2
		Value		Content
		(Btu/lb)		(lbs/MMBtu)		Owned		Leased		Recoverable Coal Reserves (As-Received)
Mine/Reserve		Approximate		Approximate		(%)		(%)		Proven		Probable		12/31/2021		12/31/2020
Oaktown Mining Complex
Oaktown Fuels No. 1 Mine		11,519		6.0		—		100.0		40.1		0.4		40.5		45.3
Oaktown Fuels No. 2 Mine		11,540		5.6		—		100.0		29.7		1.2		30.9		34.9
Total Recoverable Coal Reserves										69.8		1.6		71.4		80.2

Oaktown Fuels No. 1 Mine

The assigned and accessible reserve base for the Oaktown Fuels No. 1 Mine contains 40.5 million tons of recoverable Indiana 43 miles southV seam coal, of Terre Haute, Indiana.which 40.5 million tons are currently permitted.  The reserve contains saleable tons which average heating content of approximately 11,519 Btu per pound with approximately 6.0 pounds of sulfur dioxide per MMBtu on an as-received basis.  Access to the Oaktown Fuels No. 1 Mine is via a 90-foot-deep box cut and a 2,200-foot slope, which facilitates the egress of coals being mined in excess of 375 feet below the surface.  Since beginning first commercial coal production in 2009, the mine workings have substantially grown, and an additional mine access (elevator) was constructed for employee and supply ingress/egress closer to the active production faces.

Oaktown Fuels No. 2 Mine

The assigned and accessible reserve base for the Oaktown Fuels No. 2 Mine contains 30.9 million tons of recoverable Indiana V seam coal, of which 25.6 million tons are currently permitted.  The reserve contains saleable tons which average heating content of approximately 11,540 Btu per pound with approximately 5.6 pounds of sulfur dioxide per MMBtu on an as-received basis.  Access to the Oaktown Fuels No. 2 Mine is via an 80-foot-deep box cut and 2,600-foot slope, which facilitates the egress of coals being mined in excess of 400 feet below the surface.  Since beginning first commercial coal production in 2013 the mines workings have substantially grown and, during 2021, an additional mine access (elevator) has been constructed for employee and supply ingress/egress closer to the active production faces.

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Historical production for our Oaktown Mining Complex during the years ended December 31, 2021, 2020, and 2019 is provided in the following table:

		Annual Saleable Production Tons
		(Million Tons)
Mine/Reserve		2021		2020		2019
Oaktown Mining Complex
Oaktown Fuels No. 1 Mine		3.5		3.4		4.2
Oaktown Fuels No. 2 Mine		2.1		1.8		2.3
Total Oaktown Mining Complex Production		5.6		5.2		6.5

Other Properties

The Company holds other recoverable coal reserves in the ILB, which are not deemed individually material.

Ace in the Hole surfaceMine (Ace) (surface) – Assigned

We have 0.05 million controlled, saleable tons at our Ace mine. The Ace mine is innear Clay City, Indiana 30in Clay County and 50 road miles southeastnortheast of Terre Haute, Indiana.the Oaktown Mine. The two primary seams are low sulfur coal (~2# SO2), which make up the vast majority of the tons controlled. Mine development began in late December 2012, and we began shipping coal in late August 2013. We also owntruck low sulfur coal from Ace to Oaktown toblend with high sulfur coal. Many utilities in the Carlislesoutheastern U.S. have scrubbers with lower sulfur limits (4.5# SO2) which cannot accept the higher sulfur contents of the ILB (4.5# - 6.5# SO2). Blending high sulfur coal to a lower sulfur specification enables us to market our high sulfur coals to more customers.

The Ace mine is a multi-seam open pit strip mine. The majority of the seams are sold raw, but some of the seams will be washed prior to sales, depending on quality. To convert the tons sold raw, the in-place tonnage is multiplied by a pit recovery of 95% based on seam thickness. To convert the tons sold washed, the in-place tonnage is multiplied by a pit recovery based on seam thickness then reduced by the projected wash plant recovery of 78% to 100% depending on the seam.

We will complete mining operations at Ace in the Hole Mine located near Carlisle, Indiana, 36 miles south of Terre Haute. The Carlisle reserve is contiguous to Oaktown 2. The Carlisle Mine is developed, but currently idle.in 2022.

 

Oaktown 1, OaktownAce in the Hole Mine #2 Reserves (surface) – Unassigned

In 2018, we leased property giving us 1.0 million controlled, saleable tons at a new location 2 and Carlisle are one large underground mining complex representing 121 million tons of controlled reserves, with three slopes, one elevator, two wash plants, and two rail facilities, located on the CSX railroad. We anticipate total capacity for the three mines to be roughly 10.5 million tons annually. Additionally, the capacitymiles southwest of our Ace in the Hole mine. Future mine development is .4being reviewed along with other opportunities.

Asset Impairment Review

See Note 2 to our consolidated financial statements.

Our Coal Contracts

In 2021, Sunrise sold 6.2 million tons annually. Thus, our total mining capacity is 10.9 million tons annually. The additionof coal to 14 power plants in four different states across nine different customers.

During 2021, we derived 95% of our Princeton Rail Loop, expected to come online inrevenue from five customers (10 power plants), with each of the spring of 2018, will also provide us new access to coal markets served by the Norfolk Southern Railway Company.

For 2017, over 67%five customers representing at least 10% of our coal sales were tosales. During 2020, we derived 79% of our revenue from four customers (6 power plants), with large scrubbed coal-fired power plants ineach of the State of Indiana. Our mines and coal reserves are strategically located in close proximity to our primaryfour customers which reduces transportation costs and thus provides us with a competitive advantage with respect to those customers; our closest customer’s plant is 13 miles away, and the farthest Indiana customer is 80 miles away. We have access to our primary customers directly through either the CSX railroad (NYSE: CSX) or the Indiana Rail Road which is majority owned by the CSX. Beginning in Q2 2018, our new Princeton Loop will be operational and allow us to access the NS Railroad (NYSE: NS), increasing our coal markets.

The majorityrepresenting at least 10% of our coal is sold to investment grade customers who have scrubbed power plants; thus, we expect to be supplying these plants for many years.sales.

 

President Trump Promotes Coal

Below isSignificant customers in 2021 include Vectren Corporation, a timelinewholly-owned subsidiary of someCenterPoint Energy (NYSE: CNP), Orlando Utility Commission (OUC), Alcoa Power Generating, Inc., a subsidiary of the milestones accomplished for the coal industry thus far under the Trump administration:

November 8, 2016

Donald Trump was elected President of the United States of America. His administration has dramatically improved the regulatory environment in which we operate.

January 20, 2017

Donald Trump was inaugurated as the 45^th President of the United States.

February 15, 2017

Both the U.S. House of Representatives and the Senate passed resolutions disapproving the Stream Protection Rule (SPR) under the Congressional Review Act (CRA). President Trump signed the resolution on February 16, 2017, and, pursuant to the CRA, the SPR "shall have no force or effect" and the Office of Surface Mining (OSM) cannot promulgate a substantially similar rule absent future legislation.

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Currently, the Federal Surface Mining Control and Reclamation Act of 1977 (SMCRA) is implemented by each State’s respective State agency, which is the Department of Reclamation in Indiana. The SPR would have mandated additional approvals from Federal Agencies, such as U.S. Fish and Wildlife. The rule would have also imposed additional baseline data collection, surface/groundwater monitoring, financial assurance requirements and numerous other requirements.

February 17, 2017

Scott Pruitt was confirmed as Administrator of the Environmental Protection Agency (EPA). As former Attorney General of the state of Oklahoma, he joined a coalition of state attorney generals in suing the EPA concerning the Clean Power Plan, the principal Obama-era policy aimed at reducing U.S. greenhouse gas emissions from the electricity sector.

February 28, 2017

President Trump signed an Executive Order regarding the “waters of the US” (WOTUS) rule.  The order requires the EPA and the Army Corps of Engineers to review the WOTUS rule and publish a proposed rule that rescinds or revises the rule as appropriate and consistent with law, keeps the Nation’s navigable waters free from pollution, promotes economic growth, minimizes regulatory uncertainty, and shows due regard for the roles of the Congress and the States under the Constitution.

In President Trump’s first full official speech to a joint session of Congress, he stated: “We’re going to stop the regulations that threaten the future and livelihood of our great coal miners.”

March 28, 2017

President Trump signed an Executive Order to dismantle many of the climate change policies enacted during the Obama era. The order takes steps to downplay the future costs of carbon emissions, walks back tracking of the federal government’s carbon emissions, rescinds a 2016 moratorium on coal leases on federal lands. It also begins the process of rescinding the EPA's Clean Power Plan to reduce carbon dioxide emissions from new and existing power plants.

April 13, 2017 

The EPA said it would review and reconsider the effluent limitations guidelines (ELG) rule which targets coal combustion generators’ ash transport wastewater, and wastewater discharges from flue-gas desulfurization and mercury control systems and would require power plants to install new treatment technologies. The rule has been challenged in court by a coalition of utilities. The EPA has issued an administrative stay to delay the compliance deadlines for the ELG rule as long as litigation is ongoing.

June 1, 2017

President Trump announced that the U.S. would pull out of the Paris Agreement steering away from a group of 194 other countries that have promised to curb planet-warming greenhouse gas emissions.

October 10, 2017

EPA Administrator Scott Pruitt announced that the EPA would seek to repeal the Clean Power Plan in its entirety.

January 25, 2018

The Trump administration eliminated a policy dictating how certain major sources of hazardous air pollutants are regulated. The repeal of the agency’s “once in, always in” policy. Under the new interpretation of the policy, “major sources” can be reclassed as “area sources,” which are subject to different standards when their emissions reach an enforceable limit.

These actions are encouraging and will be important to us and the U.S. energy sector.

Our Coal Contracts

We sell coal to the following customers: Duke EnergyAlcoa Corporation (NYSE:  DUK)AA), Hoosier Energy, an electric cooperative, Indianapolis Power & Light Company (IPL), a wholly-owned subsidiary of The AES Corporation (NYSE: AES), Vectrenand Duke Energy Corporation (NYSE: VVC), and Orlando Utility Commission (OUC)DUK). In 2018, we have signed new

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Of our 2021 sales, contracts with two plants we have never73% were shipped to before. Onelocations in the State of Indiana.

Upon closing the purchase of the new customers is certainly dueMerom Power Plant, we anticipate Hallador Power Company consuming 45% of Sunrise Coal’s production by 2024.

In Q4 2021, customer coal inventories and natural gas (a competitor to coal) inventory levels were both lower than normal.  Customers returned to market this year, and we are increasing production to meet the additionincreasing demand. We are increasing production to 7 million clean tons annually starting in 2022 and expect to maintain that pace into the foreseeable future.

		Contracted				Estimated
		tons				price
Year		(millions)*				per ton
2022			6.8			$	39.81
2023			5.3			$	43.10
2024 - 2027			6.3				**
Total			18.4

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*     Contracted tons are subject to adjustment in instances of force majeure and exercise of customer options to either take additional tons or reduce tonnage if such option exists in the customer contract.

**   Unpriced or partially priced tons

Of significant note, both the reopening of the economy post Covid-19 related lockdowns and the supply disruption created by the conflict between Russia and Ukraine have significantly increased demand for U.S. steam coal. This has led to higher pricing both for coal and electricity.  All of our Princeton Rail Loop on the Norfolk Southern Railroad. The other2022 coal and electricity supply is to a plant locatedpriced, but we anticipate participating in the Carolinas. We attribute the latter to the trend of ILB coals replacing coals from higher cost eastern basins.coal and electricity prices in 2023.

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The table below reflects our projected tons. Some of our contracts contain language that allow our customers to increase or decrease tonnages throughout the year. In some cases, our customers are required to purchase their additional tonnage needs from us. We have 17.7 million tons committed for the next 5 years (2018 to 2022), which represents 51% of our current projected sales.

		Targeted tons				Committed tons								Estimated price
Year		(millions)				(millions)				% Committed				per ton
2018			6.8				6.4				94	%		$	40.00
2019			7.0				4.5				64	%		$	41.00

 

We expect to continue selling a significant portion of our coal under supply agreements with terms of one year or longer. Typically, customers enter into coal supply agreements to secure reliable sources of coal at predictable prices while we seek stable sources of revenue to support the investments required to open, expand and maintain, or improve productivity at the mines needed to supply these contracts. The terms of coal supply agreements result from competitive bidding and extensive negotiations with customers.

 

Asset Impairment Review

See Note 2Some utility customers have proposed shuttering certain plant units or entire plants in the coming years.  It remains to be seen whether these plans will be implemented. Upon completion of the acquisition of the Merom Power Plant from Hoosier Energy, we anticipate our consolidated financial statements.mines will need to produce at a 7 million-ton annualized pace for several years.

 

Reserve Table - Controlled Tons (in millions):

						2017 Year-End Reserves
		Tons				Annual
		Sold				Capacity				Proven				Probable				Total				Sulphur #				BTU
Oaktown 1 (assigned)			3.771				4.0				41.5				9.6				51.1				5.9				11,600
Oaktown 2 (assigned)			2.552				4.0				30.7				12.2				42.9				5.7				11,600
Carlisle (assigned)			-				2.5				21.8				5.5				27.3				4.4				11,500
Ace in the Hole (assigned)			0.240				0.4				0.9				-				0.9				2.0				10,900
Bulldog (unassigned)			-				-				19.6				16.2				35.8				4.5				11,300
Total			6.563				10.9				114.5				43.5				158.0
Assigned																			122.2
Unassigned																			35.8
Total																			158.0

Our assigned underground coal reserves are high sulfur (4.0# – 6.5#) with an average BTU content in the 11,500 -11,600 range. Our reserves have lower chlorine (<0.12%) than average ILB reserves of 0.22%.  Much of the ILB’s new production is located in Illinois and possesses chlorine content in excess of .30%.  The relatively low chlorine content of our reserves is attractive to buyers given their desire to limit the corrosive effects of chlorine in their power plants. As discussed below, the Ace surface mine is low sulfur (2.0#) with an average BTU content of 10,900. We have no metallurgical coal reserves, only steam (thermal) coal reserves. Below is a discussion of our current projects. Only tons greater than 4 feet in thickness are included in our underground reserves.

Oaktown 1 Mine (underground) – Assigned

We have 51.1 million controlled, salable tons of the Indiana #V coal seam. We began 2017 with 56.9 million tons controlled. Besides production, the remainder of the decrease relates to tons that were deemed unrecoverable due to geologic conditions combined with increases for new drilling and new leases. Oaktown 1 reserves are located in Knox County, IN.

Access to the Oaktown 1 Mine is via a 90-foot-deep box cut and a 2,200-foot slope, reaching coal in excess of 375 feet below the surface. In 2017, we added an elevator 7 miles from the slope allowing miners to enter closer to the active face, thereby reducing unproductive daily travel time.

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Oaktown 2 Mine (underground) – Assigned

We have 42.9 million controlled, saleable tons of the Indiana #V coal seam. We began 2017 with 53.5 million controlled tons. Besides production, the remainder of the decrease relates to tons that were deemed unrecoverable due to geologic and economic conditions based on new drilling. Oaktown 2 reserves are located in both Knox County, Indiana and Lawrence County, Illinois.

Access to the Oaktown 2 Mine is via an 80-foot-deep box cut and a 2,600-foot slope, reaching coal in excess of 400 feet below the surface.

Our underground mines are room and pillar mines that utilize developed entries for ventilation and transportation. Continuous miners extract coal from rooms by removing coal from the seam, leaving pillars to support the roof.  Coal haulers are used to transport coal to a conveyor belt for transport to the surface.  The two Oaktown mines are separated by a sandstone channel.  The coal seam thickness ranges from 4 feet to over 9 feet.  The Oaktown mines share the same wash plant which is rated at 1,800 tons per hour.  The two mines are connected to a rail loadout that can store two 120 car trains at once and is serviced by the CSX Railroad and Indiana Railroad.  Coal is also transported via truck to customers.

Carlisle Mine (underground) – Assigned

We have 27.3 million controlled, saleable tons at our Carlisle Mine. The mine is located near the town of Carlisle, Indiana in Sullivan County and became operational in January 2007. The coal is accessed with a slope to a depth of 340'. The coal is mined in the Indiana #V coal seam which is highly volatile bituminous coal and has been extensively mined by underground and surface methods in the general area. The coal thickness in the project area is 4' to 7'. The Carlisle Mine is completely developed but was idle for the entirety of 2017.

Ace in the Hole Mine (Ace) (surface) – Assigned

The Ace mine is near Clay City, Indiana in Clay County and 42 road miles northeast of the Carlisle Mine. We control .9 million tons of proven coal reserves of which we own ..5 million tons in fee.  The two primary seams are low sulfur coal (~2# SO₂), which make up .8 million of the .9 million tons controlled.  Mine development began in late December 2012, and we began shipping coal in late August 2013.  We truck low sulfur coal from Ace to Oaktown to blend with high sulfur coal. Many utilities in the southeastern U.S. have scrubbers with lower sulfur limits (4.5# SO₂) which cannot accept the higher sulfur contents of the ILB (4.5# - 6.5# SO₂). Blending high sulfur coal to a lower sulfur specification enables us to market our high sulfur coals to more customers. We expect the maximum capacity of Ace to be 0.4 tons annually.

The Ace mine is a multi-seam open pit strip mine. The majority of the seams are sold raw, but some of the seams will be washed prior to sales depending on quality. To convert the tons sold raw, the in-place tonnage is multiplied by a pit recovery of 94% based on seam thickness. To convert the tons sold washed, the in-place tonnage is multiplied by a pit recovery based on seam thickness then reduced by the projected wash plant recovery of 72%.

Bulldog Reserves (underground) – Unassigned

We have leased roughly 19,300 acres in Vermilion County, Illinois near the village of Allerton.  Based on our reserve estimates we currently control 35.8 million tons of coal.  A considerable amount of our leased acres has yet to receive any exploratory drilling.

In October 2017, we entered into an agreement to sell land associated with the Bulldog Mine for $4.9 million. As part of the transaction, we will hold the rights to repurchase the property for eight years. Also in October 2017, the Illinois Department of Natural Resources (ILDNR) notified us that our mine application, along with modifications, was acceptable. The permit will be issued upon submittal of a fee and bond which is required to be submitted within 12 months of the notification.

Full-scale mine development will not commence until we have a sales commitment. We estimate the costs to develop this mine to be $150 million at full capacity of 3.0 million tons annually.

Unassigned reserves represent coal reserves that would require new mineshafts, mining equipment, and plant facilities before operations could begin on the property. The primary reason for this distinction is to inform investors which coal reserves will require substantial capital expenditures before production can begin.

33

Below is a map that shows the locations of our mines.

 

Railroad Legend:

CSX – CSX Railroad

INRD – Indiana Rail Road

ISRR – Indiana Southern Railroad

NS – Norfolk Southern Railway

Mine and Wash Plant Recovery and Capacity

		Mine recovery				Wash plant recovery*				Wash Plant Capacity (Clean Tons)
Oaktown 1			49	%			81	%		8.0 million**
Oaktown 2			49	%			81	%
Carlisle			53	%			81	%		2.5 million
Bulldog			45	%			77	%

* Does not include out-of-seam material extracted during the mining process.

** Oaktown 1 and Oaktown 2 share the wash plant.

Liquidity and Capital Resources

																		2025 and
Contractual Obligations (in thousands)		Total				2018				2019-2021				2022-2024				thereafter
Long-term debt (matures August, 2019)		$	201,992			$	35,000			$	166,992			$	-			$	-
Future interest obligations			15,700				10,100				5,600				-				-
Reclamation obligations			13,806				300				5,315				3,011			$	5,180
		$	231,498			$	45,400			$	177,907			$	3,011			$	5,180

34

��

 

As set forth in our StatementConsolidated Statements of Cash Flows, cash provided by operations was $62$48.0 million and $52.6 million for 2017.the years ended December 31, 2021 and 2020 respectively. Operating cash flow decreased primarily due to a reduction in operating margins brought on by lower pricing and increased costs.  Operating margin per ton decreased in 2021 to $7.35/ton from $9.49/ton in 2020, reducing operating cash flow by $11.3 million.  This amountreduction was adequateoffset by changes in certain working capital items, specifically our significant inventory reduction from 2020.

Our capital expenditure budget for 2022 is $25 million, of which $15 million is for maintenance capex.  We also have scheduled payments on long-term debt totaling $25.7 million. We expect cash from operations for 2022 and the utilization of our revolver, if necessary, to fund our maintenance capital expenditures for coal properties of $11.1 million,and our debt service requirementsservice.

In 4Q21, we generated lower than expected EBITDA due to elevated cash costs related to: i) a temporary decrease in efficiency, as new hires were integrated into the workforce to support more shifts required to fulfill the significant increase in contracted tonnage, and ii) a lower yield on coal mined due to mining of $36.6 million, anda coal face ~10.5 miles away from the slope. We amended our dividend of $4.9 million. Our capex budget for 2018 is $31 million, of which $16 million is for maintenance capex. Cash from operations for 2018 should again fundbank agreement in March 2022 to provide covenant relief to maintain our maintenance capital expenditures, debt service, and our dividend.liquidity levels as costs are anticipated to improve in 2022.

 

See Note 35 to our consolidated financial statements for additional discussion about our bank debt.debt and related liquidity.

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Off-Balance Sheet Arrangements

 

Other than our surety bonds for reclamation, we have no material off-balance sheet arrangements. Included in the contractual obligations table areWe have recorded reclamation obligations of $13.8$14.1 million, which arewith the long-term portion presented as asset retirement obligations (ARO) and the remainder in accounts payable and accrued liabilities in our accompanying balance sheets. In the event we are not able to perform reclamation, we have surety bonds in place totaling $25$23.5 million to cover ARO.

 

Capital Expenditures (capex)

 

For 2017,the year ended December 31, 2021, our capex was $28.6$28.1 million allocated as follows (in millions):

Oaktown – maintenance capex		$	9.0
Oaktown – investment			19.0
Other			0.1
Capex per the Consolidated Statements of Cash Flows		$	28.1

Results of Operations

 

Oaktown – investment		$	10.1
Oaktown – maintenance capex			11.1
Princeton Rail Loop			6.3
Other projects			1.1
Capex per the Consolidated Statement of Cash Flows		$	28.6

I.	2021 Net Loss of $3.8 million.

 

35a.

Sales:  We shipped 6.2 million tons during 2021, an increase over the 6.0 million tons shipped in 2020.

i.

Coal inventory was reduced by $17.0 million during the year.

 

b.

Production:  2021 production costs were $32.16/ton.  2020 costs were slightly better at $31.07/ton.  Oaktown costs over that same period were $30.34 and $29.84, respectively.

i.

In November 2021, we completed construction and put into service an employee and supply hoist closer to the operating face reducing travel time and related labor costs.

ii.

We experienced supply chain disruptions with some vendors, causing us to pay premium prices for some of our inputs.  We expect these increases to dissipate throughout 2022.

c.

Cash Flow & Debt: We generated $48.0 million in operating cash flow during the year, which we utilized to pay down our bank debt by $26.0 million.  The Small Business Administration notified us in the third quarter of 2021 that the entire $10 million borrowed under the Paycheck Protection Program had been completely forgiven.

i.

As of December 31, 2021, our bank debt was $111.7 million, bringing our liquidity to $33.4 million and our leverage ratio to 2.34X, within our covenant of 3.0X.

 

Results

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Contents

 

The following tabletables presenting our quarterly results of operations should be read in conjunction with the consolidated financial statements and related notes included in Item 8 of their Annual Report onthis Form 10-K. We have prepared the unaudited information on the same basis as our audited consolidated financial statements. Our operating results for any quarter are not necessarily indicative of results for any future quarters or for a full year.

The following table presentstables present our unaudited quarterly results of operations for the eight quarters ended December 31, 2017. This table includes2021, and include all adjustments, consisting only of normal recurring adjustments, that we consider necessary for fair presentation of our consolidated operating results for the quarters presented.

 

		Dec-31				Sep-30				Jun-30				Mar-31				Dec-31				Sep-30				Jun-30				Mar-31
		2017				2017				2017				2017				2016				2016				2016				2016
Revenue:
Coal sales		$	68,922			$	73,896			$	62,829			$	62,555			$	71,495			$	65,360			$	66,274			$	75,795
Equity income (loss) in equity method investments			(62	)			169				27				231				(1,130	)			(80	)			174				(400	)
Other			440				403				1,456				767				869				487				2,116				490
Total revenue		$	69,300			$	74,468			$	64,312			$	63,553			$	71,234			$	65,767			$	68,564			$	75,885
Costs and expenses:
Operating costs and expenses			52,025				54,354				44,079				39,692				50,663				46,940				45,397				49,777
DD&A			9,962				9,729				9,101				9,703				9,385				7,942				9,056				9,182
ARO accretion			221				219				214				207				265				260				255				249
Coal exploration costs			288				152				275				139				505				354				395				419
SG&A			2,883				2,859				6,578				2,658				2,444				2,585				2,729				2,762
Interest			2,751				3,229				3,342				3,091				2,148				2,601				4,497				5,596
Asset impairment			-				-				-				-				16,560				-				-				-
Total cost and expenses			68,130				70,542				63,589				55,490				81,970				60,682				62,329				67,985
Income (loss) before income taxes			1,170				3,926				723				8,063				(10,736	)			5,085				6,235				7,900
Less income taxes:
Current			(1,590	)			(2,532	)			1,357				17				103				(270	)			(768	)			768
Deferred			(18,597	)			2,542				(1,023	)			632				(7,012	)			1,033				1,150				970
Total income taxes			(20,187	)			10				334				649				(6,909	)			763				382				1,738
Net income (loss)			21,357				3,916				389				7,414				(3,827	)			4,322				5,853				6,162
Net income (loss) per share:
Basic and diluted		$	0.69			$	0.13			$	0.01			$	0.25			$	(0.13	)		$	0.14			$	0.19			$	0.21
Weighted average shares outstanding:
Basic and diluted			29,830				29,774				29,503				29,413				29,287				29,252				29,251				29,251

		Mar-31				Jun-30				Sep-30				Dec-31
		2021				2021				2021				2021				Total 2021
SALES AND OPERATING REVENUES:
Coal sales		$	45,879			$	54,600			$	79,036			$	64,388			$	243,903
Other revenues			816				1,038				786				1,123				3,763
Total revenue			46,695				55,638				79,822				65,511				247,666
EXPENSES:
Operating expenses			34,009				42,456				67,792				54,583				198,840
Depreciation, depletion and amortization			10,307				9,715				9,842				10,109				39,973
Asset impairment			—				—				—				1,588				1,588
Asset retirement obligations accretion			363				373				380				388				1,504
Asset retirement obligations change in estimate			—				—				—				(3,510	)			(3,510	)
Exploration costs			58				159				96				169				482
General and administrative			2,821				3,383				3,067				5,562				14,833
Total operating expenses			47,558				56,086				81,177				68,889				253,710
LOSS FROM OPERATIONS			(863	)			(448	)			(1,355	)			(3,378	)			(6,044	)
Bank interest			(2,135	)			(2,307	)			(2,167	)			(1,901	)			(8,510	)
Non-cash interest			237				125				59				41				462
Gain on extinguishment of debt			—				—				10,000				—				10,000
Equity method investment income			—				63				90				211				364
INCOME (LOSS) BEFORE INCOME TAXES			(2,761	)			(2,567	)			6,627				(5,027	)			(3,728	)
INCOME TAX EXPENSE (BENEFIT):
Current			—				—				—				—				—
Deferred			(1,729	)			397				(1,359	)			2,717				26
Total income tax expense (benefit)			(1,729	)			397				(1,359	)			2,717				26
NET INCOME (LOSS)		$	(1,032	)		$	(2,964	)		$	7,986			$	(7,744	)		$	(3,754	)
NET INCOME (LOSS) PER SHARE:
Basic and diluted		$	(0.03	)		$	(0.10	)		$	0.26			$	(0.25	)		$	(0.12	)
WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic and diluted			30,611				30,613				30,613				30,618				30,614

 

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Oaktown’s operating costs were $27.59/ton and $30.44/ton for the year and quarter ended December 31, 2017, respectively. We expect Oaktown’s costs to range from $28 to $30 for 2018. For 2018, we expect our SG&A to be $11 million annually and costs associated with the Prosperity and Carlisle mines to be $6 million annually (reflected in operating costs and expenses).

		Mar-31				Jun-30				Sep-30				Dec-31
		2020				2020				2020				2020				Total 2020
SALES AND OPERATING REVENUES:
Coal sales		$	61,932			$	50,473			$	64,754			$	64,925			$	242,084
Other revenues			551				377				493				736				2,157
Total revenue			62,483				50,850				65,247				65,661				244,241
EXPENSES:
Operating expenses			48,469				36,165				46,570				54,753				185,957
Depreciation, depletion and amortization			10,627				10,217				9,315				9,485				39,644
Asset Impairment			—				—				1,799				—				1,799
Asset retirement obligations accretion			333				343				348				357				1,381
Exploration costs			253				208				174				133				768
General and administrative			2,978				2,678				3,131				2,807				11,594
Total operating expenses			62,660				49,611				61,337				67,535				241,143
INCOME (LOSS) FROM OPERATIONS			(177	)			1,239				3,910				(1,874	)			3,098
Bank interest			(2,654	)			(2,842	)			(2,714	)			(2,443	)			(10,653	)
Non-cash interest			(3,060	)			8				385				290				(2,377	)
Equity method investment income (loss)			55				1,231				(119	)			(113	)			1,054
INCOME (LOSS) BEFORE INCOME TAXES			(5,836	)			(364	)			1,462				(4,140	)			(8,878	)
INCOME TAX EXPENSE (BENEFIT):
Current			(524	)			—				(74	)			—				(598	)
Deferred			(1,652	)			(618	)			(387	)			597				(2,060	)
Total income tax expense (benefit)			(2,176	)			(618	)			(461	)			597				(2,658	)
NET INCOME (LOSS)		$	(3,660	)		$	254			$	1,923			$	(4,737	)		$	(6,220	)
NET INCOME (LOSS) PER SHARE:
Basic and diluted		$	(0.12	)		$	0.01			$	0.06			$	(0.15	)		$	(0.20	)
WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic and diluted			30,420				30,423				30,465				30,475				30,446

 

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Quarterly coal sales and cost data follow (in 000’s, except for per ton data and wash plant recovery percentage):

  

		1st 2017				2nd 2017				3rd 2017				4th 2017				T4Qs
All Mines																						1st 2021				2nd 2021				3rd 2021				4th 2021				T4Qs
Tons produced			1,917				1,647				1,487				1,561				6,612				1,592				1,292				1,440				1,447				5,771
Tons sold			1,555				1,548				1,786				1,685				6,574				1,174				1,403				2,042				1,554				6,173
Coal sales		$	62,555			$	62,829			$	73,896			$	68,922			$	268,202			$	45,879			$	54,600			$	79,036			$	64,388			$	243,903
Average price/ton		$	40.23			$	40.59			$	41.38			$	40.90			$	40.80			$	39.08			$	38.92			$	38.71			$	41.43			$	39.51
Wash plant recovery in %			71	%			69	%			70	%			68	%							74	%			69	%			73	%			70	%
Operating costs		$	39,692			$	44,079			$	54,354			$	52,025			$	190,150			$	33,907			$	42,364			$	67,694			$	54,583			$	198,548
Average cost/ton		$	25.53			$	28.47			$	30.43			$	30.88			$	28.92			$	28.88			$	30.20			$	33.15			$	35.12			$	32.16
Margin		$	22,863			$	18,750			$	19,542			$	16,897			$	78,052			$	11,972			$	12,236			$	11,342			$	9,805			$	45,355
Margin/ton		$	14.70			$	12.11			$	10.94			$	10.03			$	11.87			$	10.20			$	8.72			$	5.55			$	6.31			$	7.35
Capex		$	5,144			$	6,711			$	9,473			$	7,294			$	28,622			$	5,720			$	5,117			$	7,238			$	9,975			$	28,050
Maintenance capex		$	2,887			$	3,032			$	2,961			$	2,520			$	11,400			$	2,343			$	1,049			$	2,324			$	3,302			$	9,018
Maintenance capex/ton		$	0.54			$	4.25			$	2.52			$	1.50			$	1.73			$	2.00			$	0.75			$	1.14			$	2.12			$	1.46

  

		1st 2016				2nd 2016				3rd 2016				4th 2016				T4Qs
All Mines																						1st 2020				2nd 2020				3rd 2020				4th 2020				T4Qs
Tons produced			1,524				1,448				1,501				1,640				6,113				1,701				1,468				1,234				1,233				5,636
Tons sold			1,629				1,464				1,485				1,739				6,317				1,526				1,244				1,585				1,613				5,968
Coal sales		$	75,795			$	66,274			$	65,360			$	71,495			$	278,924			$	61,932			$	50,473			$	64,754			$	64,925			$	242,084
Average price/ton		$	46.53			$	45.27			$	44.01			$	41.11			$	44.15			$	40.58			$	40.57			$	40.85			$	40.25			$	40.56
Wash plant recovery in %			65	%			63	%			68	%			67	%							74	%			76	%			71	%			68	%
Operating costs		$	49,777			$	45,397			$	46,940			$	50,663			$	192,777			$	48,334			$	36,001			$	46,444			$	54,640			$	185,419
Average cost/ton		$	30.56			$	31.01			$	31.61			$	29.13			$	30.52			$	31.67			$	28.94			$	29.30			$	33.87			$	31.07
Margin		$	26,018			$	20,877			$	18,420			$	20,832			$	86,147			$	13,598			$	14,472			$	18,310			$	10,285			$	56,665
Margin/ton		$	15.97			$	14.26			$	12.40			$	11.98			$	13.64			$	8.91			$	11.63			$	11.55			$	6.38			$	9.49
Capex		$	6,053			$	1,822			$	3,935			$	8,022			$	19,832			$	5,999			$	4,006			$	3,995			$	6,661			$	20,661
Maintenance capex		$	2,984			$	904			$	1,709			$	5,301			$	10,898			$	3,470			$	2,578			$	1,365			$	2,342			$	9,755
Maintenance capex/ton		$	1.83			$	0.62			$	1.15			$	3.05			$	1.73			$	2.27			$	2.07			$	0.86			$	1.45			$	1.63

 

20172021 v. 20162020

 

For 2017,2021, we sold 6,574,0006,173,000 tons at an average price of $40.80/$39.51/ton. For 2016,2020, we sold 6,317,0005,968,000 tons at an average price of $44.15/$40.56/ton. The decrease in average price per ton is the result ofresults from our changing contract mix caused by the expiration of contracts and the acquisition of othernew contracts.  2022 pricing is expected to be comparable to 2021 at approximately $40 per ton.  2023 pricing is expected to improve as we take advantage of the higher pricing environment and is projected at just over $43 per ton based on the current tons under contract.

 

Operating expenses for our coal mines averaged $32.16/ton and $31.07/ton for the years ended December 31, 2021 and 2020, respectively.  Oaktown costs over the periods were $30.34 and expenses averaged $28.92/ton ($27.59/ton at$29.84, respectively. The majority of our operatingproduction cost increase was a result of approaching the end of our Ace in the Hole Mine’s reserve life.  We anticipate the Ace reserve reaching its end in mid-2022 and being replaced with a new reserve.  At Oaktown, mines) in 2017 comparedwe added 17% to $30.52/ton ($28.02/ton at our operating Oaktown mines) in 2016.  The reduction in cost was due to two primary factors. First,workforce as we made a conscious effortbegin to increase production in the first half of the year in anticipation of stronger market demand. Second, we addedfrom a 6.2 million-ton pace to over 7 million tons annually.  It will take time and training for our new haulage equipmentworkforce to some of the units at the Oaktown mines creating production efficiencies of up to 30% to those units. Both of these factors combined led to an 8% increase in production. In Q4 2017, we also openedreach top efficiency and productivity.  Additionally, as expected and announced, adding a new elevatorproduction unit required mining through challenging conditions during Q4 2021 and completed in Q1 2022. We expect operating costs for our coal mines to be elevated in Q1 2022, but to average $29-$31 per ton for the full year 2022.

Operating expenses associated with the idled Prosperity mine were $1.0 million for both years ended December 31, 2021 and 2020.  We expect operating costs to be $1.0 million in 2022. 

Other revenues increased $1.6 million in 2021.  Coal storage contracts and deferral fees charged for tons carried over from 2020 account for $0.8 million.  The remainder represents royalty income on owned minerals that we began collecting in mid-2020.

General and administrative expenses increased $3.2 million in 2021 as a result of increased legal and financing costs associated with the Merom Power Plant acquisition and other projects.  We expect general and administrative expenses for 2022 to remain elevated at Oaktown 1 which reduces miner travel time, and$13 - $14 million while we acquired additional haulage equipment which will continue to maintain our low-cost structure.complete the Merom Power Plant acquisition.

 

Our Sunrise Coal employees and contractors totaled 736797 at December 31, 20172021, compared to 742682 at December 31, 2016.

SG&A costs2020.  As previously stated, the significant increase is due to increased in 2017 by $4.5 million due primarily to a stock bonus of $3.8 million awarded to executives as reported indemand for our 8-K filed May 17, 2017, increased RSU amortization and employee pay increases in 2017.coal going forward.

 

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Table of Contents

Signs of Improvement for the Coal Market

I.

Natural Gas - Forward Nymex gas prices (a competitor to coal) average $5.11 for the remainder of 2022, $4.05 for 2023 and $3.51 for 2024. These gas prices cause coal plants to dispatch prior to gas especially in Indiana where ~80% of our coal is sold. Gas prices are significantly higher than recent history and should remain strong until additional production occurs.

II.	Coal Exports - U.S. export prices are significantly higher than recent history due to energy shortfalls in Asia and Europe, resulting in very strong exports in comeing years.

a.

API 4 (Asia)

372021:

Mid $80s / tonne

2022:

$202 / tonne