Item 1A. Risk Factors.
We operate in a rapidly changing environment that involves a number of risks. The following discussion highlights some of these risks and others are discussed elsewhere in this report. These and other risks could materially and adversely affect our business, financial condition, prospects, operating results or cash flows. The following risk factors are not an exhaustive list of the risks associated with our business. New factors may emerge or changes to these risks could occur that could materially affect our business.
Risks Associated with Our Operations
Our profitability depends upon the prices we receive for our coal.
We operate in a competitive and highly regulated industry that has experienced strong headwinds. Depressed coal prices have reduced our revenues, and sustained prices at current levels or further declines in coal prices will adversely affect our operating results and financial condition. Further declines in coal prices will adversely affect the value of our coal reserves.
Coal prices are dependent upon factors beyond our control, including:
•the demand for electricity and capacity utilization of electricity generating units (whether coal or non-coal);
•changes in the fuel consumption and dispatch patterns of electric power generators, whether based on economic or non-economic factors;
•the proximity, capacity and cost of transportation and terminal facilities;
•competition with and the availability, quality and price of coal and alternative fuels, including natural gas, fuel oil, nuclear, hydroelectric, wind, biomass and solar power;
•governmental regulations and taxes, including tariffs or other trade restrictions as well as those establishing air emission standards for coal-fueled power plants or mandating or subsidizing increased use of electricity from renewable energy sources;
•the strength of the global economy;
•the global supply and production costs of thermal and metallurgical coal;
•the demand for steel, which may lead to price fluctuations in the monthly and quarterly repricing of our metallurgical coal contracts;
•weather patterns, severe weather and natural disasters;
•regulatory, administrative and judicial decisions, including those affecting future mining permits and leases; and
•technological developments, including those related to alternative energy sources, those intended to convert coal-to-liquids or gas and those aimed at capturing, using and storing carbon dioxide.
Thermal coal accounted for the majority of our coal sales by volume during 2020 and 2019. The vast majority of our sales of thermal coal were to electric power generators. The demand for coal consumed for electric power generation is affected by many of the factors described above, but primarily by (i) the overall demand for electricity; (ii) the availability, quality and price of competing fuels, such as natural gas, nuclear fuel, oil and alternative energy sources; (iii) utilization of all electricity generating units (whether using coal or not), including the relative cost of producing electricity from multiple fuels, including coal; (iv) stringent environmental and other governmental regulations; and (v) the coal inventories of utilities. Gas-fueled generation has displaced and is expected to continue to displace coal-fueled generation (particularly from older, less efficient coal-fueled generation units) as current and potentially increasing regulatory costs and other factors impact the operating decisions of electric power generators. In addition, some electric power generators have made decisions to close coal-fueled generation units given ongoing pressure to shift away from coal generation. Many of the new power plants in the U.S. may be fueled by natural gas because gas-fired plants have been less expensive to construct, permits to construct these plants are easier to obtain based on emissions profiles, and electric power generators may face public and governmental pressure to generate a larger portion of their electricity from natural gas-fueled units and alternative energy sources. Increasingly stringent regulations along with stagnant electricity demand have also reduced the number of new power plants being built. These trends have reduced demand for our coal and the related prices. Any further reduction in the amount of coal consumed by electric power generators could reduce the volume and price of coal that we mine and sell.
We produce metallurgical coal that is used in the global steel industry. Metallurgical coal accounted for approximately 17% and 22% of our revenues in 2020 and 2019, respectively. Changes in governmental policies and regulations and changes in the steel industry, including the demand for steel, could reduce the demand for our metallurgical coal. Lower demand for metallurgical coal in international markets could reduce the amount of metallurgical coal that we sell and the prices that we receive for it, thereby reducing our revenues and adversely impacting our earnings and the value of our coal reserves.
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The balance between coal demand and supply, factoring in demand and supply of closely related and competing segments such as natural gas, both domestically and internationally, could materially reduce coal prices and therefore materially reduce our revenues and profitability. We compete with other fuel sources used for electricity generation, such as natural gas and renewables. Our seaborne products compete with other producers as well as other fuel sources. Declines in the price of natural gas could cause demand for coal to decrease and adversely affect the price of coal. Sustained periods of low natural gas prices or low prices for other fuels may also cause utilities to phase out or close existing coal-fueled power plants or reduce construction of new coal-fueled power plants. In the U.S., no new coal-fueled power plants are being constructed or reopened after closure. These closures could have a material adverse effect on demand and prices for our coal, thereby reducing our revenues and materially and adversely affecting our business and results of operations.
If a substantial number of our long-term coal supply agreements, including those with our largest customers, terminate, or if the pricing, volumes or other elements of those agreements materially adjust, our revenues and operating profits could suffer if we are unable to find alternate buyers willing to purchase our coal on comparable terms to those in our contracts.
Most of our sales are made under coal supply agreements, which are important to the stability and profitability of our operations. The execution of a satisfactory coal supply agreement is frequently the basis on which we undertake the development of coal reserves required to be supplied under the contract, particularly in the U.S. For the year ended December 31, 2020, we derived 32% of our revenues from coal supply agreements from our five largest customers. Those five customers were supplied primarily from 28 coal supply agreements (excluding trading and brokerage transactions) expiring at various times from 2021 to 2026.
Many of our coal supply agreements contain provisions that permit the parties to adjust the contract price upward or downward at specified times. We may adjust these contract prices based on inflation or deflation, price indices and/or changes in the factors affecting the cost of producing coal, such as taxes, fees, royalties and changes in the laws regulating the mining, production, sale or use of coal. In a limited number of contracts, failure of the parties to agree on a price under those provisions may allow either party to terminate the contract. We may experience reductions in coal prices in new long-term coal supply agreements replacing some of our expiring contracts. Coal supply agreements also typically contain force majeure provisions allowing temporary suspension of performance by us or the customer during the duration of specified events beyond the control of the affected party. Some coal supply agreements allow customers to vary the volumes of coal that they are required to purchase during a particular period, and where coal supply agreements do not explicitly allow such variation, customers sometimes request that we amend the agreements to allow for such variation. Most of our coal supply agreements contain provisions requiring us to deliver coal meeting quality thresholds for certain characteristics such as Btu, sulfur content, ash content, volatile matter, coking properties, grindability and ash fusion temperature. Failure to meet these specifications could result in economic penalties, including price adjustments, the rejection of deliveries or termination of the contracts. Moreover, some of these agreements allow our customers to terminate their contracts in the event of changes in regulations affecting our industry that restrict the use or type of coal permissible at the customer’s plant or increase the price of coal beyond specified limits.
On an ongoing basis, we discuss the extension of existing agreements or entering into new long-term agreements with various customers, but these negotiations may not be successful and these customers may not continue to purchase coal from us under long-term supply agreements.
The operating profits we realize from coal sold under supply agreements depend on a variety of factors. In addition, price adjustment and other contract provisions may increase our exposure to short-term coal price volatility. If a substantial portion of our coal supply agreements were modified or terminated, we could be materially adversely affected to the extent that we are unable to find alternate buyers for our coal at the same level of profitability. Prices for coal vary by mining region and country. As a result, we cannot predict the future strength of the coal industry overall or by mining region and cannot provide assurance that we will be able to replace existing long-term coal supply agreements at the same prices or with similar profit margins when they expire. In addition, our revenue could be adversely affected by a decline in customer purchases (including contractually obligated purchases) due to lack of demand and oversupply, cost of competing fuels and environmental and other governmental regulations.
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Risks inherent to mining could increase the cost of operating our business, and events and conditions that could occur during the course of our mining operations could have a material adverse impact on us.
Our mining operations are subject to conditions that can impact the safety of our workforce, delay coal deliveries or increase the cost of mining at particular mines for varying lengths of time. These conditions include:
•elevated gas levels;
•fires and explosions, including from methane gas or coal dust;
•accidental mine water discharges;
•weather, flooding and natural disasters;
•hazardous events such as roof falls and high wall or tailings dam failures;
•seismic activities, ground failures, rock bursts or structural cave-ins or slides;
•key equipment failures;
•variations in coal seam thickness, coal quality, the amount of rock and soil overlying coal deposits, and geologic conditions impacting mine sequencing;
•delays in moving our longwall equipment;
•unexpected maintenance problems; and
•unforeseen delays in implementation of mining technologies that are new to our operations.
We maintain insurance policies that provide limited coverage for some of the risks referenced above, which may lessen the impact associated with these risks. However, there can be no assurance as to the amount or timing of recovery under our insurance policies in connection with losses associated with these risks.
Our take-or-pay arrangements could unfavorably affect our profitability.
We have substantial take-or-pay arrangements, predominately in Australia, totaling $1.2 billion, with terms ranging up to 22 years, that commit us to pay a minimum amount for rail and port commitments for the delivery of coal even if those commitments go unused. The take-or-pay provisions in these contracts sometimes allow us to apply amounts paid for subsequent deliveries, but these provisions have limitations and we may not be able to apply all such amounts so paid in all cases. Also, we may not be able to utilize the amount of capacity for which we have previously paid. Additionally, we may continue to deliver coal during times when it might otherwise be optimal to suspend operations because these take-or-pay provisions effectively convert a variable cost of selling coal to a fixed operating cost.
We may not recover our investments in our mining, exploration and other assets, which may require us to recognize impairment charges related to those assets.
The value of our assets have 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; declining coal-fired electricity generation; lower-than-expected coal pricing; technical and geological operating difficulties; an inability to economically extract our coal reserves; and unanticipated increases in operating costs. During the years ended December 31, 2020 and 2019, the Company recorded $1,487.4 million and $270.2 million of impairment charges related to such factors, as further described in Note 3. “Asset Impairment” to the accompanying consolidated financial statements. These factors may trigger the recognition of additional impairment charges in the future, which could have a substantial impact on our results of operations.
Because of the volatile and cyclical nature of coal markets, it is reasonably possible that our current estimates of projected future cash flows from our mining assets may change in the near term, which may result in the need for adjustments to the carrying value of our assets.
We could be negatively affected if we fail to maintain satisfactory labor relations.
As of December 31, 2020, we had approximately 4,600 employees (excluding employees that were employed at operations classified as discontinued), which included approximately 3,500 hourly employees. We are party to labor agreements with various labor unions that represent certain of our employees. Such labor agreements are negotiated periodically, and, therefore, we are subject to the risk that these agreements may not be able to be renewed on reasonably satisfactory terms. Approximately 29% of our hourly employees were represented by organized labor unions and generated approximately 18% of our coal production for the year ended December 31, 2020. Relations with our employees and, where applicable, organized labor are important to our success. If some or all of our current non-union operations were to become unionized, we could incur an increased risk of work stoppages, reduced productivity and higher labor costs. Also, if we fail to maintain good relations or successfully negotiate contracts with our employees who are represented by unions, we could potentially experience labor disputes, strikes, work stoppages, slowdowns or other disruptions in production that could negatively impact our profitability.
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We could be adversely affected if we fail to appropriately provide financial assurances for our obligations.
U.S. federal and state laws and Australian laws require us to provide financial assurances related to requirements to reclaim lands used for mining, to pay federal and state workers’ compensation, to provide financial assurances for coal lease obligations and to satisfy other miscellaneous obligations. The primary methods we use to meet those obligations are to provide a third-party surety bond or provide a letter of credit. As of December 31, 2020, we had $1,633.6 million of outstanding surety bonds and $437.6 million of letters of credit with third parties in order to provide required financial assurances for post-mining reclamation, workers’ compensation and other insurance obligations, coal lease-related and other obligations and performance guarantees.
Our financial assurance obligations may increase or become more costly due to a number of factors, and surety bonds and letters of credit may not be available to us, particularly in light of some banks and insurance companies’ announced unwillingness to support thermal coal producers and other fossil fuel companies. Alternative forms of financial assurance such as self-bonding have been severely restricted or terminated in most of the regions where our mines reside. Our failure to retain, or inability to obtain, surety bonds, bank guarantees or letters of credit, or to provide a suitable alternative, could have a material adverse effect on us. That failure could result from a variety of factors including the following:
•lack of availability, higher expense or unfavorable market terms of new surety bonds, bank guarantees or letters of credit; and
•inability to provide or fund collateral for current and future third-party issuers of surety bonds, bank guarantees or letters of credit.
As further described in “Liquidity and Capital Resources” of Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” the Company reached a surety transaction support agreement with the providers of 99% of its surety bond portfolio to resolve approximately $800 million in additional collateral demands made by the sureties. The sureties have agreed to a standstill through December 31, 2024, during which time, the sureties will not demand any additional collateral, draw on letters of credit posted for the benefit of themselves, or cancel any existing surety bond. Our failure to provide adequate collateral, or abide by other terms in the agreement, could invalidate the agreement and materially and adversely affect our business and results of operations.
Our failure to maintain adequate bonding would invalidate our mining permits and prevent mining operations from continuing, which could result in our inability to continue as a going concern.
Our mining operations are extensively regulated, which imposes significant costs on us, and future regulations and developments could increase those costs or limit our ability to produce coal.
The coal mining industry is subject to regulation by federal, state and local authorities with respect to matters such as:
•workplace health and safety;
•limitations on land use;
•mine permitting and licensing requirements;
•reclamation and restoration of mining properties after mining is completed;
•the storage, treatment and disposal of wastes;
•remediation of contaminated soil, sediment and groundwater;
•air quality standards;
•water pollution;
•protection of human health, plant-life and wildlife, including endangered or threatened species and habitats;
•protection of wetlands;
•the discharge of materials into the environment; and
•the effects of mining on surface water and groundwater quality and availability.
Regulatory agencies have the authority under certain circumstances following significant health and safety incidents to order a mine to be temporarily or permanently closed. In the event that such agencies ordered the closing of one of our mines, our production and sale of coal would be disrupted and we may be required to incur cash outlays to re-open the mine. Any of these actions could have a material adverse effect on our financial condition, results of operations and cash flows.
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New legislation, regulations or orders related to the environment or employee health and safety may be adopted and may materially adversely affect our mining operations, our cost structure or our customers’ ability to use coal. New legislation or administrative regulations (or new interpretations by the relevant government of existing laws, regulations and approvals), including proposals related to the protection of the environment or the reduction of greenhouse gas emissions that would further regulate and tax the coal industry, may also require us or our customers to change operations significantly or incur increased costs. Some of our coal supply agreements contain provisions that allow a purchaser to terminate its contract if legislation is passed that either restricts the use or type of coal permissible at the purchaser’s plant or results in specified increases in the cost of coal or its use. These factors and legislation, if enacted, could have a material adverse effect on our financial condition and results of operations.
For additional information about the various regulations affecting us, see the sections entitled “Regulatory Matters—U.S.” and “Regulatory Matters —Australia.”
Our operations may impact the environment or cause exposure to hazardous substances, and our properties may have environmental contamination, which could result in material liabilities to us.
Our operations currently use hazardous materials and generate limited quantities of hazardous wastes from time to time. A number of laws, including in the U.S., CERCLA and RCRA, impose liability relating to contamination by hazardous substances. Such liability may involve the costs of investigating or remediating contamination and damages to natural resources, as well as claims seeking to recover for property damage or personal injury caused by hazardous substances. Such liability may arise from conditions at formerly, as well as currently, owned or operated properties, and at properties to which hazardous substances have been sent for treatment, disposal or other handling. Liability under RCRA, CERCLA and similar state statutes is without regard to fault, and typically is joint and several, meaning that a person may be held responsible for more than its share, or even all, of the liability involved.
We may be unable to obtain, renew or maintain permits necessary for our operations, or we may be unable to obtain, renew or maintain such permits without conditions on the manner in which we run our operations, which would reduce our production, cash flows and profitability.
Numerous governmental and tribal permits and approvals are required for mining operations. The permitting rules, and the interpretations of these rules, are complex, change frequently and are often subject to discretionary interpretations by regulators, all of which may make compliance more difficult or impractical. As part of this permitting process, when we apply for permits and approvals, we are required to prepare and present to governmental authorities data pertaining to the potential impact or effect that any proposed exploration for or production of coal may have upon the environment. The public, including non-governmental organizations, opposition groups and individuals, have statutory rights to comment upon and submit objections to requested permits and approvals (including modifications and renewals of certain permits and approvals) and otherwise engage in the permitting process, including bringing citizens’ lawsuits to challenge the issuance of permits, the validity of environmental impact statements or the performance of mining activities. In recent years, the permitting required for coal mining has been the subject of increasingly stringent regulatory and administrative requirements and extensive litigation by environmental groups.
Additionally, our operations may be affected by sites within or near mining areas deemed to have cultural heritage significance to indigenous peoples, and our mining permits may be rescinded or modified, or our mining plans may be voluntarily adjusted, to mitigate against adverse impacts to such sites.
The costs, liabilities and requirements associated with these permitting requirements and any related opposition may be extensive and time-consuming and may delay commencement or continuation of exploration or production which would adversely affect our coal production, cash flows and profitability. Further, required permits may not be issued or renewed in a timely fashion or at all, or permits issued or renewed may be conditioned in a manner that may restrict our ability to efficiently and economically conduct our mining activities, any of which would materially reduce our production, cash flows and profitability.
Concerns about the impacts of coal combustion on global climate are increasingly leading to consequences that have affected and could continue to affect demand for our products or our securities and our ability to produce, including increased governmental regulation of coal combustion and unfavorable investment decisions by electricity generators.
Global climate issues continue to attract public and scientific attention. Numerous reports, such as the Fourth and the 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 greenhouse gases, including emissions of carbon dioxide from coal combustion by power plants.
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The enactment of future laws, the passage of regulations, or other executive orders regarding emissions from the use of coal by the U.S., some of its states or other countries, or other actions to limit such emissions, could result in electricity generators switching from coal to other fuel sources. Further, policies limiting available financing for the development of new coal mines or coal-fueled power stations could adversely impact the global supply and demand for coal. The potential financial impact on us of such future laws, regulations or other policies will depend upon the degree to which any such laws or regulations force electricity generators to diminish their reliance on coal as a fuel source. That, in turn, will depend on a number of factors, including the specific requirements imposed by any such laws, regulations or other policies, the time periods over which those laws, regulations or other policies would be phased in, the state of development and deployment of CCUS technologies as well as acceptance of CCUS technologies to meet regulations and the alternative uses for coal. Similarly, higher-efficiency coal-fired power plants may also be an option for meeting laws or regulations related to emissions from coal use. Several countries, including some major coal users such as China, India and Japan, included using higher-efficiency coal-fueled power plants in their plans under the Paris Agreement. From time to time, we attempt to analyze the potential impact on the Company of as-yet-unadopted, potential laws, regulations and policies. Such analyses require that we make significant assumptions as to the specific provisions of such potential laws, regulations and policies, which sometimes show that if implemented in the manner assumed by the analyses, the potential laws, regulations and policies could result in material adverse impacts on our operations, financial condition or cash flows. We do not believe that such analyses reasonably predict the quantitative impact that future laws, regulations or other policies may have on our results of operations, financial condition or cash flows.
Numerous 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.
Several non-governmental organizations have undertaken campaigns to minimize or eliminate the use of coal as a source of electricity generation in the U.S. and across the globe. In an effort to stop or delay coal mining activities, activist groups have brought lawsuits challenging the issuance of individual coal leases, and challenging the federal coal leasing program more broadly. Other lawsuits challenge historical and pending regulatory approvals, permits and processes that are necessary to conduct coal mining operations or to operate coal-fueled power plants, including so-called “sue and settle” lawsuits where regulatory authorities in the past have reached private agreements with environmental activists that often involve additional regulatory restrictions or processes being implemented without formal rulemaking.
The effect of these and other similar developments has made it more costly and difficult to maintain our business. These cost increases and/or substantial or extended declines in the prices we receive for our coal due to these or other factors could reduce our revenue and profitability, cash flows, liquidity, and value of our coal reserves and could result in material losses.
Our trading and hedging activities do not cover certain risks and may expose us to earnings volatility and other risks.
In addition to coal price volatility, we are currently subject to price volatility on diesel fuel utilized in our mining operations and the Australian dollar. We may in the future enter into hedging arrangements to manage these risks, or other exposures.
Some of these hedging instruments may require us to post margin based on the value of those instruments and other credit factors. If the fair value of our hedge portfolio moves significantly, or if laws or regulations are passed requiring all hedge arrangements to be exchange-traded or exchange-cleared, we could be required to post additional margin, which could negatively impact our liquidity.
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If the assumptions underlying our asset retirement obligations for reclamation and mine closures are materially inaccurate, our costs could be significantly greater than anticipated.
Our asset retirement obligations primarily consist of spending estimates for surface land reclamation and support facilities at both surface and underground mines in accordance with federal and state reclamation laws in the U.S. and Australia as defined by each mining permit. These obligations are determined for each mine using various estimates and assumptions including, among other items, estimates of disturbed acreage as determined from engineering data, estimates of future costs to reclaim the disturbed acreage and the timing of these cash flows, which is driven by the estimated economic life of the mine and the applicable reclamation laws. These cash flows are discounted using a credit-adjusted, risk-free rate. Our management and engineers periodically review these estimates. If our assumptions do not materialize as expected, actual cash expenditures and costs that we incur could be materially different than currently estimated. Moreover, regulatory changes could increase our obligation to perform reclamation, mine closing and post-closure activities. The resulting estimated asset retirement obligation could change significantly if actual amounts change significantly from our assumptions, which could have a material adverse effect on our results of operations and financial condition.
Our future success depends upon our ability to continue acquiring and developing coal reserves that are economically recoverable.
Our recoverable reserves decline as we produce coal. We have not yet applied for the permits required or developed the mines necessary to use all of our reserves. Moreover, the amount of proven and probable coal reserves described in Part I, Item 2. “Properties” involves the use of certain estimates and those estimates could be inaccurate. Actual production, revenues and expenditures with respect to our coal reserves may vary materially from estimates.
Our future success depends upon our conducting successful exploration and development activities or acquiring properties containing economically recoverable reserves. Our current strategy includes increasing our reserves through acquisitions of government and other leases and producing properties and continuing to use our existing properties and infrastructure. In certain locations, leases for oil, natural gas and coalbed methane reserves are located on, or adjacent to, some of our reserves, potentially creating conflicting interests between us and lessees of those interests. Other lessees’ rights relating to these mineral interests could prevent, delay or increase the cost of developing our coal reserves. These lessees may also seek damages from us based on claims that our coal mining operations impair their interests. Additionally, the U.S. federal government limits the amount of federal land that may be leased by any company to 75,000 acres in any one state and 150,000 acres nationwide. As of December 31, 2020, we leased a total of 44,645 acres from the federal government subject to those limitations.
Our planned mine development projects and acquisition activities may not result in significant additional reserves, and we may not have success developing additional mines. Most of our mining operations are conducted on properties owned or leased by us. Our right to mine some of our reserves may be materially adversely affected if defects in title or boundaries exist. In order to conduct our mining operations on properties where these defects exist, we may incur unanticipated costs. In addition, in order to develop our reserves, we must also own the rights to the related surface property and receive various governmental permits. We cannot predict whether we will continue to receive the permits or appropriate land access necessary for us to operate profitably in the future. We may not be able to negotiate or secure new leases from the government or from private parties, obtain mining contracts for properties containing additional reserves or maintain our leasehold interest in properties on which mining operations have not commenced or have not met minimum quantity or product royalty requirements. From time to time, we have experienced litigation with lessors of our coal properties and with royalty holders. In addition, from time to time, our permit applications and federal and state coal leases have been challenged, causing production delays.
To the extent that our existing sources of liquidity are not sufficient to fund our planned mine development projects and reserve acquisition activities, we may require access to capital markets, which may not be available to us or, if available, may not be available on satisfactory terms. If we are unable to fund these activities, we may not be able to maintain or increase our existing production rates and we could be forced to change our business strategy, which could have a material adverse effect on our financial condition, results of operations and cash flows.
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We face numerous uncertainties in estimating our economically recoverable coal reserves and inaccuracies in our estimates could result in lower than expected revenues, higher than expected costs and decreased profitability.
Coal is economically recoverable when the price at which our coal can be sold exceeds the costs and expenses of mining and selling the coal. The costs and expenses of mining and selling the coal are determined on a mine-by-mine basis, and as a result, the price at which our coal is economically recoverable varies based on the mine. Forecasts of our future performance are based on, among other things, estimates of our recoverable coal reserves. We base our reserve information on engineering, economic and geological data assembled and analyzed by our staff and third parties, which includes various engineers and geologists. The reserve estimates as to both quantity and quality are updated from time to time to reflect production of coal from the reserves and new drilling or other data received. There are numerous uncertainties inherent in estimating quantities and qualities of coal and costs to mine recoverable reserves, including many factors beyond our control. Estimates of economically recoverable coal reserves necessarily depend upon a number of variable factors and assumptions, any one of which may, if incorrect, result in an estimate that varies considerably from actual results. These factors and assumptions include:
•geologic and mining conditions, which may not be fully identified by available exploration data and may differ from our experience in areas we currently mine;
•demand for coal;
•current and future market prices for coal, contractual arrangements, operating costs and capital expenditures;
•severance and excise taxes, royalties and development and reclamation costs;
•future mining technology improvements;
•the effects of regulation by governmental agencies;
•the ability to obtain, maintain and renew all required permits;
•employee health and safety; and
•historical production from the area compared with production from other producing areas.
As a result, actual coal tonnage recovered from identified reserve areas or properties and revenues and expenditures with respect to our reserves may vary materially from estimates. Thus, these estimates may not accurately reflect our actual reserves. Any material inaccuracy in our estimates related to our reserves could result in lower than expected revenues, higher than expected costs or decreased profitability which could materially and adversely affect our business, results of operations, financial position and cash flows. Additionally, our reserve estimates may be adversely affected in the future by the SEC’s recent rule amendments revising property disclosure requirements for publicly-traded mining companies. We will be required to comply with these new rules in 2021.
Joint ventures, partnerships or non-managed operations may not be successful and may not comply with our operating standards.
We participate in several joint venture and partnership arrangements and may enter into others, all of which necessarily involve risk. Whether or not we hold majority interests or maintain operational control in our joint ventures, our partners may, among other things, (1) have economic or business interests or goals that are inconsistent with, or opposed to, ours; (2) seek to block actions that we believe are in our or the joint venture’s best interests; or (3) be unable or unwilling to fulfill their obligations under the joint venture or other agreements, such as contributing capital, each of which may adversely impact our results of operations and our liquidity or impair our ability to recover our investments.
Where our joint ventures are jointly controlled or not managed by us, we may provide expertise and advice but have limited control over compliance with our operational standards. We also utilize contractors across our mining platform, and may be similarly limited in our ability to control their operational practices. Failure by non-controlled joint venture partners or contractors to adhere to operational standards that are equivalent to ours could unfavorably affect safety results, operating costs and productivity and adversely impact our results of operations and reputation.
We may undertake further repositioning plans that would require additional charges.
As a result of our continuing review of our business or changing demand, we may choose to further modify our portfolio of operations and/or reduce our workforce in the future. These actions may result in further restructuring charges, cash expenditures and the consumption of management resources, any of which could cause our operating results to decline and may fail to yield the expected benefits.
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Our business, results of operations, financial condition and prospects could be materially and adversely affected by the recent COVID-19 pandemic and the related effects on public health.
Our operations are susceptible to widespread outbreaks of illness or other public health issues, such as the continuing global COVID-19 pandemic. The COVID-19 pandemic could have a material adverse effect on our business, results of operations, financial condition and prospects, including our ability to comply with covenants under our debt agreements.
The COVID-19 pandemic has caused governments around the world, including in the U.S. and Australia, to implement quarantines, travel bans and shutdowns, which have significantly restricted the movement of people and goods. The continuing spread of COVID-19 has contributed to adverse changes in general domestic and global economic conditions and disrupted domestic and international credit markets. Within the global coal industry, supply and demand disruptions resulting from the COVID-19 pandemic have been widespread and have adversely impacted us and our customers, as further described in Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
Governmental mandates, and our efforts to act in the best interests of our employees, customers, suppliers, vendors and joint venture and other business partners, have affected and are continuing to affect our business and operations, causing us to modify a number of our normal business practices. Additional governmental mandates could require forced shutdowns of our mines and other facilities for extended or indefinite periods and widespread outbreaks in locations significant to our operations could adversely affect our workforce, resulting in serious health issues and absenteeism. In addition, the COVID-19 pandemic may cause supply chains and distribution channels to be interrupted, slowed or rendered inoperable. If our operations are curtailed, we may need to seek alternate sources of supply for commodities, services and labor, which may be more expensive. Alternate sources may not be available or may result in delays in shipments to our customers. Further, if our customers’ businesses are similarly affected, they might delay, reduce or cancel purchases from us. Adverse changes in the general domestic and global economic conditions and disrupted domestic and international credit markets, could negatively affect our customers’ ability to pay us as well as our ability to access capital that could negatively affect our liquidity.
Despite our efforts to manage these realized and potential impacts, their ultimate impact also depends on factors beyond our knowledge or control, including the duration and severity of the COVID-19 pandemic as well as third-party actions taken to contain its spread and mitigate its public health effects. While the ultimate impacts of the COVID-19 pandemic on our business are unknown, we expect continued interference with general commercial activity, which may further negatively affect both demand and prices for our products. We also face disruption to supply chain and distribution channels, potentially increasing costs of production, storage and distribution, and potential adverse effects to our workforce, each of which could have a material adverse effect on our business, financial condition, results of operations and prospects.
Our expenditures for postretirement benefit obligations could be materially higher than we have predicted if our underlying assumptions prove to be incorrect.
We pay postretirement health and life insurance benefits to eligible retirees. Our total accumulated postretirement benefit obligation related to such benefits was a liability of $442.9 million as of December 31, 2020, of which $29.7 million was classified as a current liability.
These liabilities are actuarially determined. We use various actuarial assumptions, including the discount rate, future cost trends, mortality tables and rates of return on plan assets to estimate the costs and obligations for these items. Our discount rate is determined by utilizing a hypothetical bond portfolio model which approximates the future cash flows necessary to service our liabilities. A decrease in the discount rate used to determine our postretirement benefit and defined benefit pension obligations could result in an increase in the valuation of these obligations, thereby increasing the cost in subsequent fiscal years. We have made assumptions related to future trends for medical care costs in the estimates of retiree health care obligations. Our medical trend assumption is developed by annually examining the historical trend of our cost per claim data. If our assumptions do not materialize as expected, actual cash expenditures and costs that we incur could differ materially from our current estimates. Moreover, regulatory changes or changes in healthcare benefits provided by the government could increase our obligation to satisfy these or additional obligations. We develop our actuarial determinations of liabilities using actuarial mortality tables we believe best fit our population’s actual results. In deciding which mortality tables to use, we periodically review our population’s actual mortality experience and evaluate results against our current assumptions as well as consider recent mortality tables published by the Society of Actuaries Retirement Plans Experience Committee in order to select mortality tables for use in our year end valuations. If our mortality tables do not anticipate our population’s mortality experience as accurately as expected, actual cash expenditures and costs that we incur could differ materially from our current estimates. Additionally, our reported defined benefit pension funding status may be affected, and we may be required to increase employer contributions, due to increases in our defined benefit pension obligation or poor financial performance in asset markets in future years.
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Our defined benefit pension plans are subject to the provisions of the Employee Retirement Income Security Act of 1974, as amended (ERISA). It is implicit in our underlying assumptions that those plans continue to operate in the normal course of business. However, the Pension Benefit Guaranty Corporation (PBGC) may terminate our plans under certain circumstances pursuant to ERISA, including in the event that the PBGC concludes that its risk may increase unreasonably if such plans continue to operate based on its assessment of the plans’ funded status, our financial condition or other factors. Termination of the plans would require us to provide immediate funding or other financial assurance to the PBGC for all or a substantial portion of the underfunded amounts, as determined by the PBGC based on its own assumptions. Those assumptions may differ from our own. Any of those consequences could have a material adverse effect on our results of operations, financial conditions or available liquidity.
We are subject to various general operating risks which may be fully or partially outside of our control.
Our results of operations, financial position or cash flows could be adversely impacted by various general operating risks which may be fully or partially outside of our control. Such risks stem from internal and external sources and include:
•global economic recessions and/or credit market disruptions;
•deterioration of the creditworthiness of our customers or counterparties to financial instruments, and their ability to perform under contracts;
•inability of suppliers and other counterparties, including those related to transportation, contract mining, service provision, and coal trading and brokerage, to fulfil the terms of their contracts with us;
•decreases in the availability or increases in costs of key supplies, capital equipment or commodities such as diesel fuel, steel, explosives and tires;
•disruption to, or increased costs within, the transportation chain for coal, including rail, barge, trucking, overland conveyor, ports and ocean-going vessels;
•failure to attract and retain skilled and qualified personnel, particularly as the prevalence of coal-fired electricity generation declines;
•new or increased forms of taxation imposed by federal, state, provincial or local governmental authorities, including production taxes, sales-related taxes, royalties, environmental taxes, mining profits taxes and income taxes;
•uncertainties associated with our global operating platform, including country and political risks, international regulatory requirements, and foreign currency rates; and
•cyber-attacks or other security breaches that disrupt our operations or result in the dissemination of proprietary or confidential information about us, our employees, our customers or other third-parties.
Risks Related to Our Indebtedness and Capital Structure
Our financial performance could be adversely affected by our Indebtedness.
As of December 31, 2020, we had approximately $1.5 billion of Indebtedness outstanding, excluding finance leases and debt issuance costs.
As more fully described within “Liquidity and Capital Resources” of Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” in January 2021 we entered into a series of interrelated transactions with our surety bond providers, the revolving lenders under our credit agreement and certain holders of our senior secured notes to extend a significant portion of our near-term debt maturities to December 2024 and to stabilize collateral requirements for our existing surety bond portfolio. While our aggregate amount of Indebtedness did not materially change as a result of these transactions, our incremental cost of borrowing and cash paid for interest expenses will increase prospectively.
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The degree to which we are leveraged could have important consequences, including, but not limited to:
•making it more difficult for us to pay interest and satisfy our debt obligations;
•increasing the cost of borrowing;
•increasing our vulnerability to general adverse economic and industry or regulatory conditions;
•requiring the dedication of a substantial portion of our cash flow from operations to the payment of principal and interest on our Indebtedness, thereby reducing the availability of our cash flow to fund working capital, capital expenditures, business development or other general corporate requirements;
•limiting our ability to obtain additional financing to fund future working capital, capital expenditures, business development or other general corporate requirements;
•limiting our ability to refinance or otherwise exchange existing debt at commercially acceptable rates;
•making it more difficult to obtain surety bonds, letters of credit, bank guarantees or other financing, particularly during periods in which credit markets are weak;
•limiting our flexibility in planning for, or reacting to, changes in our business and in the coal industry;
•causing a decline in our credit ratings; and
•placing us at a competitive disadvantage compared to less leveraged competitors.
In addition, our Indebtedness subjects us to certain restrictive covenants. Failure by us to comply with these covenants could result in an event of default that, if not cured or waived, could have a material adverse effect on us and result in amounts outstanding thereunder to be immediately due and payable. The terms of our Indebtedness provide that if we cannot meet our debt service obligations, the lenders could foreclose against the assets securing their borrowings and we could be forced into bankruptcy or liquidation.
A downgrade in our credit ratings or other unfavorable indicators could result in, among other matters, a requirement to post additional collateral on derivative trading instruments that we may enter into, the loss of trading counterparties for corporate hedging and trading and brokerage activities or an increase in the cost of, or a limit on our access to, various forms of credit used in operating our business.
If our cash flows and capital resources are insufficient to fund our debt service obligations, we may be forced to sell assets, seek additional capital or seek to restructure or refinance our Indebtedness. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations. Our Indebtedness may restrict the use of the proceeds from any such sales. We may not be able to complete those sales and the proceeds may not be adequate to meet any debt service obligations then due.
Despite our Indebtedness, we may still be able to incur more debt, which could further increase the risks associated with our Indebtedness.
We may be able to incur additional Indebtedness in the future. Although covenants under the indentures governing our senior secured notes and the agreements governing our other Indebtedness, including our credit facility, revolver and finance leases, limit our ability to incur additional Indebtedness, these restrictions are subject to a number of qualifications and exceptions and, under certain circumstances, debt incurred in compliance with these restrictions can be material. In addition, the indenture governing the senior secured notes and the agreements governing our other Indebtedness do not limit us from incurring obligations that do not constitute Indebtedness as defined therein.
The terms of the indentures governing our senior secured notes and the agreements and instruments governing our other Indebtedness and surety bonding obligations impose restrictions that may limit our operating and financial flexibility.
The indentures governing our senior secured notes and the agreements governing our other Indebtedness and surety bonding obligations contain certain restrictions and covenants which restrict our ability to incur liens and/or debt or provide guarantees in respect of obligations of any other person and other restrictions, all of which could adversely affect our ability to operate our business, as well as significantly affect our liquidity, and therefore could adversely affect our results of operations.
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These covenants limit, among other things, our ability to:
•incur additional Indebtedness;
•pay dividends on or make distributions in respect of stock or make certain other restricted payments, such as share repurchases;
•make capital investments;
•enter into agreements that restrict distributions from certain subsidiaries;
•sell or otherwise dispose of assets;
•use for general purposes the cash received from certain allowable asset sales or disposals;
•enter into transactions with affiliates;
•create or incur liens;
•merge, consolidate or sell all or substantially all of our assets; and
•receive dividends or other payments from subsidiaries in certain cases.
Our ability to comply with these covenants may be affected by events beyond our control and we may need to refinance existing debt in the future. A breach of any of these covenants together with the expiration of any cure period, if applicable, could result in a default under our senior secured notes. If any such default occurs, subject to applicable grace periods, the holders of our senior secured notes may elect to declare all outstanding senior secured notes, together with accrued interest and other amounts payable thereunder, to be immediately due and payable. If the obligations under our senior secured notes were to be accelerated, our financial resources may be insufficient to repay the notes and any other Indebtedness becoming due in full.
In addition, if we breach the covenants in the indentures governing the senior secured notes and do not cure such breach within the applicable time periods specified therein, we would cause an event of default under the indenture governing the senior secured notes and a cross-default to certain of our other Indebtedness and the lenders or holders thereunder could accelerate their obligations. If our Indebtedness is accelerated, we may not be able to repay our Indebtedness or borrow sufficient funds to refinance it. Even if we are able to obtain new financing, it may not be on commercially reasonable terms or on terms that are acceptable to us. If our Indebtedness is in default for any reason, our business, financial condition and results of operations could be materially and adversely affected. In addition, complying with these covenants may make it more difficult for us to successfully execute our business strategy and compete against companies who are not subject to such restrictions.
The number and quantity of viable financing and insurance alternatives available to us may be significantly impacted by unfavorable lending and investment policies by financial institutions and insurance companies associated with concerns about environmental impacts of coal combustion, and negative views around our efforts with respect to environmental and social matters and related governance considerations could harm the perception of our company by a significant number of investors or result in the exclusion of our securities from consideration by those investors.
Certain banks, other financing sources and insurance companies have taken actions to limit available financing and insurance coverage for the development of new coal-fueled power plants and coal producers and utilities that derive a majority of their revenue from coal, and particularly from thermal coal. This may adversely impact the future global demand for coal. Increasingly, the actions of such financial institutions and insurance companies are informed by non-standardized “sustainability” scores, ratings and benchmarking studies provided by various organizations that assess environmental, social and governance matters. Further, there have been efforts in recent years by members of the general financial and investment communities, including investment advisors, sovereign wealth funds, public pension funds, universities and other institutional investors, to divest themselves and to promote the divestment of securities issued by companies involved in the fossil fuel extraction market, or that have low ratings or scores in studies and assessments of the type noted above, including coal producers. These entities also have been pressuring lenders to limit financing available to such companies. These efforts may have adverse consequences, including, but not limited to:
•restricting our ability to access capital and financial markets in the future;
•reducing the demand and price for our equity securities;
•increasing the cost of borrowing;
•causing a decline in our credit ratings;
•reducing the availability, and/or increasing the cost of, third-party insurance;
•increasing our retention of risk through self-insurance;
•making it more difficult to obtain surety bonds, letters of credit, bank guarantees or other financing; and
•limiting our flexibility in business development activities such as mergers, acquisitions and divestitures.
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Risks Related to Ownership of Our Securities
The price of our securities may be volatile and could fall below the minimum allowed by New York Stock Exchange (NYSE) listing requirements.
The price of our common stock (Common Stock) may fluctuate due to a variety of market and industry factors that may materially reduce the market price of our Common Stock regardless of our operating performance, including, among others:
•actual or anticipated fluctuations in our quarterly and annual results and those of other public companies in our industry;
•industry cycles and trends;
•mergers and strategic alliances in the coal industry;
•changes in government regulation;
•potential or actual military conflicts or acts of terrorism;
•the failure of securities analysts to publish research about us or to accurately predict the results we actually achieve;
•changes in accounting principles;
•announcements concerning us or our competitors;
•the purchase and sale of shares of our Common Stock by significant shareholders;
•lack of trading liquidity; and
•the general volatility of securities markets.
As a result of all of these factors, investors in our Common Stock may not be able to resell their stock at or above the price they paid or at all. In the recent past, our closing stock price has fallen below $1.00 per share for a limited number of trading days. If our stock were to trade below $1.00 per share for 30 consecutive trading days, NYSE could commence suspension and delisting procedures. Further, we could be the subject of securities class action litigation due to any such stock price volatility, which could divert management’s attention and have a material adverse effect on our results of operation.
Our Common Stock is subject to dilution and may be subject to further dilution in the future.
Our Common Stock is subject to dilution from our long-term incentive plan. In addition, in the future, we may issue equity securities in connection with future investments, acquisitions or capital raising transactions. Such issuances or grants could constitute a significant portion of the then-outstanding Common Stock, which may result in significant dilution in ownership of Common Stock.
There may be circumstances in which the interests of a significant stockholder could be in conflict with other stakeholders’ interests.
Circumstances may arise in which the interests of a significant stockholder may be in conflict with the interests of our other stakeholders. A significant stockholder may exert substantial influence over us to cause us to take action that aligns with their interests, for example, to pursue or prevent acquisitions, divestitures or other transactions, including the issuance or repurchase of additional shares or debt, that, in its judgment, could enhance its investment in us or another company in which it invests. Such transactions may advance the interests of the significant stockholder and not necessarily those of other stakeholders, which might adversely affect us or other holders of our Common Stock or debt instruments.
The payment of dividends on our stock or repurchases of our stock is dependent on a number of factors, and future payments and repurchases cannot be assured.
As more fully described within “Liquidity and Capital Resources” of Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” during the fourth quarter of 2020, we entered into transaction support agreements with our surety bond providers which prohibit the payment of dividends on our stock or repurchases of our stock through December 31, 2024, unless otherwise agreed to by the parties to the agreements. Restrictive covenants in our credit facility and in the indentures governing our senior secured notes also limit our ability to pay cash dividends and repurchase shares. Such restrictions may negatively impact the trading price of the Common Stock. The payment of future cash dividends and future repurchases will depend upon these restrictions, as well as our earnings, economic conditions, liquidity and capital requirements, and other factors, including our leverage and other financial ratios. Accordingly, we cannot make any assurance that future dividends will be paid or future repurchases will be made.
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General Business Risks
We may not be able to fully utilize our deferred tax assets.
We are subject to income and other taxes in the U.S. and numerous foreign jurisdictions, most significantly Australia. As of December 31, 2020, we had gross deferred income tax assets, including net operating loss (NOL) carryforwards, and liabilities of $2,311.6 million and $54.4 million, respectively, as described further in Note 10. “Income Taxes” to the accompanying consolidated financial statements. At that date, we also had recorded a valuation allowance of $2,287.3 million.
The Company’s ability to use its NOL carryforwards may be limited if it experiences an “ownership change” as defined in Section 382 (Section 382) of the Internal Revenue Code of 1986, as amended. An ownership change generally occurs if certain stockholders increase their aggregate percentage ownership of a corporation’s stock by more than 50 percentage points over their lowest percentage ownership at any time during the testing period, which is generally the three-year period preceding any potential ownership change.
Although we may be able to utilize some or all of those deferred tax assets in the future if we have income of the appropriate character in those jurisdictions (subject to loss carryforward and tax credit expiry, in certain cases), there is no assurance that we will be able to do so. Further, we are presently unable to record tax benefits on future losses in the U.S. and Australia until such time as sufficient income is generated by our operations in those jurisdictions to support the realization of the related net deferred tax asset positions. Our results of operations, financial condition and cash flows may adversely be affected in future periods by these limitations.
Acquisitions and divestitures are a potentially important part of our long-term strategy, subject to our investment criteria, and involve a number of risks, any of which could cause us not to realize the anticipated benefits.
We may engage in acquisition or divestiture activity based on our set of investment criteria to produce outcomes that increase shareholder value or provide potential strategic benefits. If we fail to accurately estimate the future results and value of an acquired or divested business or assets and the related risk associated with such a transaction, or are unable to successfully integrate the businesses or assets we acquire, our business, financial condition or results of operations could be negatively affected. Moreover, any transactions we pursue could materially impact our liquidity and an acquisition could increase capital resource needs and may require us to incur Indebtedness, seek equity capital or both. We may not be able to satisfy these liquidity and capital resource needs on acceptable terms or at all. In addition, future acquisitions could result in our assuming significant long-term liabilities, including potentially unknown liabilities, relative to the value of the acquisitions.
Our certificate of incorporation and by-laws include provisions that may discourage a takeover attempt.
Provisions contained in our certificate of incorporation and by-laws and Delaware law could make it more difficult for a third-party to acquire us, even if doing so might be beneficial to our stockholders. Provisions of our by-laws and certificate of incorporation impose various procedural and other requirements that could make it more difficult for stockholders to effect certain corporate actions. These provisions could limit the price that certain investors might be willing to pay in the future for shares of our Common Stock and may have the effect of delaying or preventing a change in control.
Diversity in interpretation and application of accounting literature in the mining industry may impact our reported financial results.
The mining industry has limited industry-specific accounting literature and, as a result, we understand diversity in practice exists in the interpretation and application of accounting literature to mining-specific issues. As diversity in mining industry accounting is addressed, we may need to restate our reported results if the resulting interpretations differ from our current accounting practices. Refer to Note 1. “Summary of Significant Accounting Policies” to the accompanying consolidated financial statements for a summary of our significant accounting policies.
Item 1B. Unresolved Staff Comments.
None.
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Item 2. Properties.
Coal Reserves
We controlled an estimated 3.0 billion tons of proven and probable coal reserves as of December 31, 2020. An estimated 2.6 billion tons of our attributable proven and probable coal reserves are in the U.S., with the remainder in Australia. Approximately 2% of our U.S. proven and probable coal reserves, or 52 million tons, are metallurgical coking coal. The remainder of our U.S. coal reserves consists of thermal coal. Approximately 56% of our Australian proven and probable coal reserves, or 243 million tons, are metallurgical coal, comprised of approximately 121 million and 122 million tons of coking coal and low-volatile pulverized coal injection (LV PCI) coals, respectively. The remainder of our Australian coal reserves consists of thermal coal. We own approximately 6% of these reserves and leased property comprises the remaining 94%. Approximately 88% of our reserves, or 2.7 billion tons, are compliance coal and 12% are non-compliance coal (assuming application of the U.S. industry standard definition of compliance coal to all of our reserves). Compliance coal is defined by Phase II of the CAA as coal having sulfur dioxide content of 1.2 pounds or less per million Btu. Electricity generators are able to use coal that exceeds these specifications by using emissions reduction technology, using emission allowance credits or blending higher sulfur coal with lower sulfur coal.
Below is a table summarizing the locations and proven and probable coal reserves of our major mining segments.
Proven and ProbableReserves as ofDecember 31, 2020 (1)
OwnedTons LeasedTons TotalTons
Mining Segment Locations
(Tons in millions)
Seaborne Thermal Mining New South Wales — 211 211
Seaborne Metallurgical Mining Queensland, New South Wales and Alabama — 275 275
Powder River Basin Mining Wyoming — 2,223 2,223
(1)Estimated proven and probable coal reserves have been adjusted to account for estimated process dilutions and losses during mining and processing involved in producing a saleable coal product.
Reserves are defined by 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. Proven and probable coal reserves are defined by SEC Industry Guide 7 as follows:
•Proven (Measured) Reserves — 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 (Indicated) Reserves — 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 (measured) reserves, is high enough to assume continuity between points of observation.
Our estimates of proven and probable coal reserves are established within these guidelines. Estimates within the proven category have the highest degree of assurance, while estimates within the probable category have only a moderate degree of geologic assurance. Further exploration is necessary to place probable reserves into the proven reserve category. Our active properties generally have a much higher degree of reliability because of increased drilling density.
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Our guidelines for geologic assurance surrounding estimated proven and probable U.S. and Australian coal reserves generally follow the respective industry-accepted practices of those countries. In the U.S., our estimated proven coal reserves lie within one-quarter mile of a valid point of measure or point of observation, such as exploratory drill holes or previously mined areas, while our estimated probable coal reserves may lie more than one-quarter mile, but less than three-quarters of a mile, from a point of thickness measurement. In Australia, our estimated proven coal reserves generally lie within 250 meters of a point of observation, while our estimated probable coal reserves may lie more than 250 meters, but less than 500 meters, from a point of observation. For some of our Australian coal reserves, the distance between points of observation is determined by a geostatistical study.
The preparation of our coal reserve estimates is completed in accordance with our prescribed internal control procedures, which include verification of input data into a coal reserve forecasting and economic evaluation software system, as well as multi-functional management review. Our reserve estimates are prepared by our staff of experienced geologists and engineers. Our corporate Technical Services group is responsible for tracking changes in reserve estimates, supervising our other geologists and coordinating periodic third-party reviews of our reserve estimates by qualified mining consultants.
Our coal reserve estimates are predicated on information obtained from an extensive historical database of drill holes and information obtained from our ongoing drilling program. We compile data from individual drill holes in a computerized drill-hole database from which the depth, thickness and, where core drilling is used, the quality of the coal is determined. The density of a drill pattern determines whether the related coal reserves will be classified as proven or probable. Our coal reserve estimates are then input into our computerized land management system, which overlays that geological data with data on ownership or control of the mineral and surface interests to determine the extent of our attributable coal reserves in a given area. Our land management system contains reserve information, including the quantity and quality (where available) of reserves, as well as production data, surface and coal ownership, lease payments and other information relating to our coal reserves and land holdings. We periodically update our coal reserve estimates to reflect production of coal from those reserves and new drilling or other data received. Accordingly, our coal reserve estimates will change from time to time to reflect the effects of our mining activities, analysis of new engineering and geological data, changes in coal reserve holdings, modification of mining methods and other factors.
Our estimate of the economic recoverability of our coal reserves is generally based upon a comparison of unassigned reserves to assigned reserves currently in production in the same geologic setting to determine an estimated mining cost. These estimated mining costs are compared to expected market prices for the quality of coal expected to be mined and take into consideration typical contractual sales agreements for the region and product. Where possible, we also review coal production by competitors in similar mining areas. Only coal reserves expected to be mined economically are included in our reserve estimates. Finally, our coal reserve estimates consider dilutions and losses during mining and processing for recoverability factors to estimate a saleable product. Factors impacting our assessment include geological conditions, production expectations for certain areas, the effects of regulation and taxes by governmental agencies, future price and operating cost assumptions and adverse changes in market conditions and mine closure activities. The estimates are also impacted by decreases resulting from current year production and increases resulting from information obtained from additional drilling. Our estimation as of December 31, 2020 reflected a net reduction compared to the prior year of 1.0 billion tons of coal reserves. The decrease was driven by production, changes to our estimates of economic recoverability to reflect market conditions, mine plan changes and new drilling.
We periodically engage independent mining and geological consultants and consider their input regarding the procedures used by us to prepare our internal estimates of coal reserves, selected property reserve estimates and tabulation of reserve groups according to standard classifications of reliability. Our December 31, 2020 reserve estimates for the Gateway North Mine and El Segundo Mine in the U.S. were audited by Weir International, Inc., independent mining and geological consulting firm, which included a review of the data, procedures and parameters employed by us in developing our reserve estimates. The audits found that the reserve estimates for the areas were (1) well documented, clearly and concisely reported and (2) prepared consistent with standard industry and geological practice, and in accordance with United States Geological Survey Circular 891 requirements and SEC Industry Guide 7 guidelines. We plan to complete additional audits of our reserve estimates on a cyclical basis for each of our major operating regions.
With respect to the accuracy of our coal reserve estimates, our experience is that recovered reserves are within plus or minus 10% of our proven and probable estimates, on average, and our probable estimates are generally within the same statistical degree of accuracy when the necessary drilling is completed to move reserves from the probable to the proven classification.
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For each mine or future mine, we employ a market-driven, risk adjusted capital allocation process to guide long-term mine planning of active operations and development projects for economically mineable coal. We refer to this process as Life-of-Mine (LOM) planning. The LOM plan projects, among other things, annual quantities and qualities for each coal product. The saleable product mix for a mine may include multiple thermal and metallurgical products with different targeted qualities. The expected volumes for each mine and product, as well as annual pricing forecasts for each product, developed as described below, and related cost forecasts, developed as described below, are then evaluated to determine the economically recoverable coal in the LOM plan.
Pricing
The pricing information used to establish our reserves includes internal, proprietary price forecasts and existing contract economics, in each case on a mine-by-mine and product-by-product basis. In general, our price forecasts are based on a thorough analytical process utilizing detailed supply and demand models, global economic indicators, projected foreign exchange rates, analyses of price relationships among various commodities, competing fuels analyses, projected steel demand, analyses of supplier costs and other variables. Price forecasts, supply and demand models and other key assumptions and analyses are stress tested against independent third-party research not commissioned by us to confirm the conclusions reached through our analytical processes, and our price forecasts fall within the ranges of the projections included in this third-party research. The development of the analyses, price forecasts, supply and demand models and related assumptions are subject to multiple levels of management review.
Below is a description of some of the specific factors that we evaluate in developing our price forecasts for thermal and metallurgical coal products on a mine-by-mine and product-by-product basis. Differences between the assumptions and analyses included in our price forecasts and realized factors could cause actual pricing to differ from our forecasts.
Thermal. Several factors can influence thermal coal supply and demand and pricing. Demand is sensitive to total electric power generation volumes, which are determined in part by the impact of weather on heating and cooling demand, inter-fuel competition in the electric power generation mix (such as from natural gas and renewable sources), changes in capacity (additions and retirements), competition from other producers, coal stockpiles and policy and regulations. Supply considerations impacting pricing include reserve positions, mining methods, strip ratios, production costs and capacity and the cost of new supply (greenfield developments or extensions at existing mines).
In the United States, natural gas is the most significant substitute for thermal coal for electricity generation and can be one of the largest drivers of shifts in supply and demand and pricing. The competitiveness of natural gas as a generation fuel source has been strengthened by accelerated growth in domestic natural gas production, new natural gas combined cycle generation capacity and comparatively low natural gas prices versus historic levels. The build out of renewable generation and subsidized power can also be a key driver of power market pricing and hence coal prices.
Internationally, thermal coal-fueled generation also competes with alternative forms of electricity generation. The competitiveness and availability of generation fueled by natural gas, oil, nuclear, hydro, wind, solar and biomass vary by country and region and can have a meaningful impact on coal pricing. Policy and regulations, which vary from country to country, can also influence prices. In addition, seaborne thermal coal import demand can be significantly impacted by the availability of domestic coal production, particularly in the two leading coal import countries, China and India, and the competitiveness of seaborne supply from leading thermal coal exporting countries, including Indonesia, Australia, Russia, Colombia, the U.S. and South Africa, among others.
Metallurgical. Several factors can influence metallurgical coal supply and demand and pricing. Demand is impacted by economic conditions, government policies and demand for steel, and is also impacted by competing technologies used to make steel, some of which do not use coal as a manufacturing input. Competition from other types of coal is also a key price consideration and can be impacted by coal quality and characteristics, delivered energy cost (including transportation costs), customer service and support and reliability of supply.
Seaborne metallurgical coal import demand can be significantly impacted by the availability of domestic coal production, particularly in leading metallurgical coal import countries such as China, among others, as well as country-specific policies restricting or promoting domestic supply. The competitiveness of seaborne metallurgical coal supply from leading metallurgical coal exporting countries of Australia, the U.S., Russia, Canada, Mongolia and Mozambique, among others, is also an important price consideration.
In addition to the factors noted above, the prices which may be obtained at each individual mine or future mine can be impacted by factors such as (i) the mine’s location, which impacts the total delivered energy costs to its customers, (ii) quality characteristics, particularly if they are unique relative to competing mines, (iii) assumed transportation costs and (iv) other mine costs that are contractually passed on to customers in certain commercial relationships.
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Costs
The cost estimates we use to establish our reserves are generally estimated according to internal processes that project future costs based on historical costs and expected trends. The estimated costs normally include mining, processing, transportation, royalty, add-on tax and other mining-related costs. Our estimated mining and processing costs reflect projected changes in prices of consumable commodities (mainly diesel fuel, explosives and steel), labor costs, geological and mining conditions, targeted product qualities and other mining-related costs. Estimates for other sales-related costs (mainly transportation, royalty and add-on tax) are based on contractual prices or fixed rates. Specific factors that may impact the cost at our various operations include:
•Geological settings. The geological characteristics of each mine are among the most important factors that determine the mining cost. Our geology department conducts the exploration program and provides geological models for the LOM process. Coal seam depth, thickness, dipping angle, partings and quality constrain the available mining methods and size of operations. Shallow coal is typically mined by surface mining methods by which the primary cost is overburden removal. Deep coal is typically mined by underground mining methods where the primary costs include coal extraction, conveyance and roof control.
•Scale of operations and the equipment sizes. For surface mines, our dragline systems generally have a lower unit cost than truck-and-shovel systems for overburden removal. The longwall operations generally are more cost effective than room-and-pillar operations for underground mines.
•Commodity prices. For surface mines, the costs of diesel fuel and explosives are major components of the total mining cost. For underground mines, the steel used for roof bolts represents a significant cost. Forecasted commodity prices are used to project those costs in the financial models we use to establish our reserves.
•Target product quality. By targeting a premium quality product, our mining and processing processes may experience more coal losses. By lowering product quality the coal losses can be minimized and therefore a lower cost per ton can be achieved. In our mine plans, the product qualities are estimated to correspond to existing contracts and forecasted market demands.
•Transportation costs. Transportation costs vary by region. Most of our U.S. thermal operations sell coal at mine loadouts. Therefore, no transportation expenses are included in our U.S. thermal cost estimates. Our seaborne operations typically sell coal at designated ports. The estimated costs for our seaborne operations include rail and barge transportation and related fees at ports.
•Royalty costs. Our royalty costs are based upon contractual agreements for the coal leased from governments or private owners. The royalty rates for coal leased from governments differ by country and, in some cases, by mining method. Estimated add-on taxes and other sales-related costs are determined according to government regulations or historical costs.
•Exchange rates. Costs related to our Australian production are predominantly denominated in Australian dollars, while the Australian coal that we export is sold in U.S. dollars. As a result, Australian/U.S. dollar exchange rates impact the U.S. dollar cost of Australian production.
Based on our mine-by-mine and product-by-product evaluations of the estimated prices for our coal, and the costs and expenses of mining and selling our coal, we have concluded our reserves were economically recoverable as of December 31, 2020.
On October 31, 2018, the SEC voted to adopt amendments to modernize the property disclosure requirements for mining registrants and related guidance under the Securities Act of 1933 and the Securities Exchange Act of 1934. The final rules provide a three-year transition period, thus, we will be required to begin to comply with the new rules for the fiscal year beginning on January 1, 2021 (reported in the Annual Report on Form 10-K for the year ended December 31, 2021). We are in the process of assessing the impact the new rules will have on our disclosures.
We have numerous U.S. federal coal leases that are administered by the U.S. Department of the Interior under the Federal Coal Leasing Amendments Act of 1976. These leases cover our principal reserves in the Powder River Basin and other reserves in Alabama, Colorado and New Mexico. Each of these leases continues indefinitely, provided there is diligent development of the property and continued operation of the related mine or mines. The U.S. Bureau of Land Management (BLM) has asserted the right to adjust the terms and conditions of these leases, including rent and royalties, after the first 20 years of their term and at 10-year intervals thereafter. Annual rents on surface land under our federal coal leases are now set at $3.00 per acre. Production royalties on federal leases are set by statute at 12.5% of the gross proceeds of coal mined and sold for surface-mined coal and 8% for underground-mined coal. The U.S. federal government limits by statute the amount of federal land that may be leased by any company and its affiliates at any time to 75,000 acres in any one state and 150,000 acres nationwide. As of December 31, 2020, we leased 1,610 acres of federal land in Alabama, 3,480 acres in Colorado, 640 acres in New Mexico and 38,915 acres in Wyoming, for a total of 44,645 acres nationwide subject to those limitations.
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Similar provisions govern three coal leases with the Navajo and Hopi Indian tribes. These leases cover coal contained in 64,783 acres of land in northern Arizona lying within the boundaries of the Navajo Nation and Hopi Indian reservations. We also lease coal-mining properties from various state governments in the U.S.
Private U.S. coal leases normally have terms of between 10 and 20 years and usually give us the right to renew the lease for a stated period or to maintain the lease in force until the exhaustion of mineable and merchantable coal contained on the relevant site. These private U.S. leases provide for royalties to be paid to the lessor either as a fixed amount per ton or as a percentage of the sales price. Many U.S. leases also require payment of a lease bonus or minimum royalty, payable either at the time of execution of the lease or in periodic installments. The terms of our private U.S. leases are normally extended by active production at or near the end of the lease term. U.S. leases containing undeveloped reserves may expire or these leases may be renewed periodically.
Mining and exploration in Australia is generally carried out under leases or licenses granted by state governments. Mining leases are typically for an initial term of up to 21 years (but which may be renewed) and contain conditions relating to such matters as minimum annual expenditures, restoration and rehabilitation. Royalties are paid to the state government as a percentage of the sales price. Generally, landowners do not own the mineral rights or have the ability to grant rights to mine those minerals. These rights are retained by state governments. Compensation is payable to landowners for loss of access to the land, and the amount of compensation can be determined by agreement or court process. Surface rights are typically acquired directly from landowners through agreement or court determination, subject to some exceptions.
Consistent with industry practice, we conduct only limited investigation of title to our coal properties prior to leasing. Title to lands and reserves of the lessors or grantors and the boundaries of our leased properties are not completely verified until we prepare to mine those reserves.
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The following charts provide a summary, by mining complex, of production (in descending order by mining segment) for the years ended December 31, 2020, 2019 and 2018, tonnage of coal reserves that are assigned to our active operating mines, our property interest in those reserves and other characteristics of the facilities.
SUMMARY OF COAL PRODUCTION AND SULFUR CONTENT OF ASSIGNED RESERVES
(Tons in millions)
Sulfur Content of Assigned Reserves as of December 31, 2020 (1)
Production Sulfur Sulfur Sulfur Received
Year Ended December 31, Type of Dioxide per Dioxide per Dioxide per Btu per
Seaborne Thermal Mining:
Seaborne Metallurgical Mining:
Millennium (4) 0.1 0.6 1.9 C/P — — — —
Powder River Basin Mining:
Other U.S. Thermal Mining:
Kayenta (7) — 3.8 6.5 T — — — —
Wildcat Hills Underground (8) — 1.4 1.3 T — — — —
Cottage Grove (9) — 0.1 0.4 T — — — —
T: Thermal
C: Coking
P: Pulverized Coal Injection Metallurgical
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ASSIGNED RESERVES (10)
(Tons in millions)
Attributable Ownership 100% Project Basis Modifying Factors (11)
Proven and Probable Reserves Proven and Probable Reserves
Seaborne Thermal Mining:
Seaborne Metallurgical Mining:
Powder River Basin Mining:
Other U.S. Thermal Mining:
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ASSIGNED AND UNASSIGNED PROVEN AND PROBABLE COAL RESERVES (10)
(Tons in millions)
Attributable Ownership 100% Project Basis
Proven and Proven and
Total Tons Probable Total Tons Probable
Seaborne Metallurgical Mining:
Other U.S. Thermal Mining:
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ASSIGNED AND UNASSIGNED - RESERVE CONTROL AND MINING METHOD
(Tons in millions)
Attributable Ownership 100% Project Basis
Reserve Control Mining Method Reserve Control Mining Method
Seaborne Metallurgical Mining:
Other U.S. Thermal Mining:
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ASSIGNED AND UNASSIGNED PROVEN AND PROBABLE COAL RESERVES - SULFUR CONTENT
(Tons in millions)
Attributable Ownership 100% Project Basis
Sulfur Content (1) Sulfur Content (1)
Type of per per per per per per Btu
Seaborne Thermal Mining (New South Wales) T/C 211 — — 244 — — 10,700
Seaborne Metallurgical Mining:
Other U.S. Thermal Mining:
T: Thermal
C: Coking
P: Pulverized Coal Injection Metallurgical
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(1)Compliance coal is defined by Phase II of the CAA as coal having sulfur dioxide content of 1.2 pounds or less per million Btu. Non-compliance coal is defined as coal having sulfur dioxide content in excess of this standard. Electricity generators are able to use coal that exceeds these specifications by using emissions reduction technology, using emission allowance credits or blending higher sulfur coal with lower sulfur coal.
(2)As-received Btu per pound includes the weight of moisture in the coal on an as-sold basis. The range of variability of the moisture content in coal across a given region may affect the actual shipped Btu content of current production from assigned reserves.
(3)Includes the Wambo Open-Cut Mine and the Wambo Underground Mine areas.
(4)The Company’s Millennium Mine ceased production in March 2020, with sales continuing throughout May 2020.
(5)Represents our 50% interest in Middlemount, which owns the Middlemount Mine in Queensland, Australia. Because that entity is accounted for as an unconsolidated equity affiliate, 2020, 2019 and 2018 tons produced by Middlemount have been excluded from the “Summary of Coal Production and Sulfur Content of Assigned Reserves” table. Middlemount produced 3.2 million tons, 2.9 million tons, and 4.2 million tons of coal in 2020, 2019 and 2018, respectively (on a 100% basis).
(6)The Company’s Somerville Central Mine ceased production in December 2020, with sales continuing into January 2021.
(7)The Company’s Kayenta Mine closed during August 2019 upon termination of its coal supply agreement with the Navajo Generating Station in Arizona.
(8)The Company’s Wildcat Hills Underground Mine ceased production in December 2019, with sales continuing throughout April 2020.
(9)The Company’s Cottage Grove Mine ceased production in May 2019, with sales continuing throughout July 2019.
(10)Assigned reserves represent recoverable coal reserves that are controlled and accessible at active operations as of December 31, 2020. Unassigned reserves represent coal at currently non-producing locations that would require significant new mine development, mining equipment or plant facilities before operations could begin on the property.
(11)The modifying factors reflect the assumptions which are utilized to convert coal quantities and qualities as in ground to run of mine (ROM) coal after mining, and eventually to saleable product coal after processing. Coal reserves are reported as an estimation of the final saleable quantity, which takes into account any losses and dilutions during mining and processing. We generally keep track of coal reserves through in place coal, ROM coal and product coal. In place coal for U.S. underground reserves excludes planned barrier pillars, but includes regular pillars from projected underground extractions. In place coal for Australian underground reserves is exclusive of all planned pillars. The difference is due to historic practice and software used by each country. The ROM factor represents the estimated ROM coal in relation to the coal in place with considerations of coal losses, dilutions and remaining pillars during mining processes. The yield is the ratio of estimated saleable product coal over ROM coal tons with mainly processing loss considered.
a.In December 2019, after receiving the requisite regulatory and permitting approvals, the Company formed an unincorporated joint venture with Glencore, in which the Company holds a 50% interest, to combine the existing operations of the Company’s Wambo Open-Cut Mine in Australia with the adjacent coal reserves of Glencore’s United Mine. The Wambo Open-Cut reserve is estimated for our 50% interest in United Wambo Joint Venture.
Item 3. Legal Proceedings.
See Note 24. “Commitments and Contingencies” to the accompanying consolidated financial statements for a description of our pending legal proceedings, which information is incorporated herein by reference.
Item 4. Mine Safety Disclosures.
Our “Safety and Sustainability Management System” has been designed to set clear and consistent expectations for safety, health and environmental stewardship across our business. It aligns to the National Mining Association’s CORESafety® framework and encompasses three fundamental areas: leadership and organization, risk management and assurance. We also partner with other companies and certain governmental agencies to pursue new technologies that have the potential to improve our safety performance and provide better safety protection for employees.
We continually monitor our safety performance and regulatory compliance. The information concerning mine safety violations or other regulatory matters required by SEC regulations is included in Exhibit 95 to this Annual Report on Form 10-K.
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PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Our Common Stock is listed on the New York Stock Exchange, under the symbol “BTU.” As of February 16, 2021 there were 140 holders of our Common Stock, as determined by counting our record holders and the number of participants reflected in a security position listing provided to us by the Depository Trust Company (DTC). Because such DTC participants are brokers and other institutions holding shares of our Common Stock on behalf of their customers, we do not know the actual number of unique shareholders represented by these record holders.
Dividend Policy
We declared and paid quarterly dividends every quarter in 2019, and a supplemental dividend was declared and paid during the first quarter of 2019. We suspended dividends in 2020. As more fully described within “Liquidity and Capital Resources” of Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” during the fourth quarter of 2020, we entered into transaction support agreements with our surety bond providers which prohibit the payment of dividends through December 31, 2024, unless otherwise agreed to by the parties to the agreements. Additionally, restrictive covenants in our credit facility and in the indentures governing our senior secured notes also limit our ability to pay cash dividends.
Share Relinquishments
We routinely allow employees to relinquish Common Stock to pay estimated taxes upon the vesting of restricted stock units and the payout of performance units that are settled in Common Stock under our equity incentive plans. The value of Common Stock tendered by employees is determined based on the closing price of our Common Stock on the dates of the respective relinquishments.
Share Repurchase Programs
On August 1, 2017, we announced that our Board of Directors authorized a share repurchase program to allow repurchases of up to $500 million of the then outstanding shares of our common stock and/or preferred stock (Repurchase Program). On April 25, 2018, we announced that the Board authorized the expansion of the Repurchase Program to $1.0 billion. On October 30, 2018, we announced that the Board authorized an additional expansion of the Repurchase Program to $1.5 billion. The Repurchase Program does not have an expiration date and may be discontinued at any time. Through December 31, 2020, we repurchased 41.5 million shares of our Common Stock for $1,340.3 million, which included commissions paid of $0.8 million, leaving $160.5 million available for share repurchase under the Repurchase Program.
We suspended share repurchases in 2019, and similar to the payment of dividends as described above, the same agreements with our surety bond providers prohibit share repurchases through December 31, 2024, unless otherwise agreed to by the parties to the agreements. Additionally, restrictive covenants in our credit facility and in the indentures governing our senior secured notes also limit our ability to repurchase shares. Prior to the suspension, repurchases were made at the Company’s discretion. The specific timing, price and size of purchases depended upon the share price, general market and economic conditions and other considerations, including compliance with various debt agreements in effect at the time the repurchases were made.
Purchases of Equity Securities
The following table summarizes all share purchases for the three months ended December 31, 2020:
(1) Includes shares withheld to cover the withholding taxes upon the vesting of equity awards, which are not a part of the Repurchase Program.
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Mandatory Conversion of Preferred Shares
Each share of our Series A Convertible Preferred Stock (Convertible Preferred Stock) that was previously outstanding was subject to mandatory automatic conversion into a number of shares of Common Stock if the volume weighted average price of the Common Stock exceeded $32.50 for at least 45 trading days in a 60 consecutive trading day period, including each of the last 20 days in such 60 consecutive trading day period. On January 31, 2018, the requirements for such a mandatory conversion were met and the then outstanding 13.2 million shares of Convertible Preferred Stock were automatically converted into 24.8 million shares of Common Stock. As a result of this mandatory conversion, we recorded a non-cash preferred dividend charge of $102.5 million during the year ended December 31, 2018. After the mandatory conversion, no shares of Convertible Preferred Stock are issued or outstanding and all rights of the prior holders of Convertible Preferred Stock have terminated.
Stock Performance Graph
The following performance graph compares the cumulative total return on our common stock from April 4, 2017, the date our common stock began trading following the effective date of our plan of reorganization, through December 31, 2020, with the cumulative total return of the following indices: (i) the S&P MidCap 400 Stock Index and (ii) Custom Composite Index (a peer group comprised of Arch Resources, Inc., Hallador Energy Co., and Warrior Met Coal, Inc.). The Custom Composite Index reflects publicly listed U.S. companies within the coal industry of similar size or product type.
The graph assumes that the value of the investment was $100 at April 4, 2017 for BTU and the Custom Composite Index (Warrior Met Coal, Inc. began trading on the New York Stock Exchange on April 13, 2017) and at March 31, 2017, for the S&P Midcap 400 Index. The graph also assumes that all dividends were reinvested and that the investments were held through December 31, 2020.
These indices are included for comparative purposes only and do not necessarily reflect management's opinion that such indices are an appropriate measure of the relative performance of the stock involved and are not intended to forecast or be indicative of possible future performance of the common stock.
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
Overview
In 2020, we produced and sold 128.8 million and 132.6 million tons of coal, respectively, from continuing operations.
As of December 31, 2020, we report our results of operations primarily through the following reportable segments: Seaborne Thermal Mining, Seaborne Metallurgical Mining, Powder River Basin Mining, Other U.S. Thermal Mining and Corporate and Other.
The business of our seaborne operating platform is primarily export focused with customers spread across several countries, with a portion of our thermal and metallurgical coal sold within Australia. Generally, revenues from individual countries vary year by year based on electricity and steel demand, the strength of the global economy, governmental policies and several other factors, including those specific to each country. We classify our seaborne mines within the Seaborne Thermal Mining or Seaborne Metallurgical Mining segments based on the primary customer base and coal reserve type of each mining operation. A small portion of the coal mined by the Seaborne Thermal Mining segment is of a metallurgical grade. Similarly, a small portion of the coal mined by the Seaborne Metallurgical Mining segment is of a thermal grade. Additionally, we may market some of our metallurgical coal products as a thermal coal product from time to time depending on market conditions.
Our Seaborne Thermal Mining operations consist of mines in New South Wales, Australia. The mines in that segment utilize both surface and underground extraction processes to mine low-sulfur, high Btu thermal coal.
Our Seaborne Metallurgical Mining operations consist of mines in Queensland, Australia, one in New South Wales, Australia and one in Alabama. The mines in that segment utilize both surface and underground extraction processes to mine various qualities of metallurgical coal (low-sulfur, high Btu coal). The metallurgical coal qualities include hard coking coal, semi-hard coking coal, semi-soft coking coal and PCI coal.
The principal business of our thermal mining segments in the U.S. is the mining, preparation and sale of thermal coal, sold primarily to electric utilities in the U.S. under long-term contracts, with a relatively small portion sold as international exports as conditions warrant. Our Powder River Basin Mining operations consist of our mines in Wyoming. The mines in that segment are characterized by surface mining extraction processes, coal with a lower sulfur content and Btu and higher customer transportation costs (due to longer shipping distances). Our Other U.S. Thermal Mining operations historically reflect the aggregation of our Illinois, Indiana, New Mexico, Colorado and Arizona mining operations. The mines in that segment are characterized by a mix of surface and underground mining extraction processes, coal with a higher sulfur content and Btu and lower customer transportation costs (due to shorter shipping distances). Geologically, our Powder River Basin Mining operations mine sub-bituminous coal deposits and our Other U.S. Thermal Mining operations mine both bituminous and sub-bituminous coal deposits.
Our Corporate and Other segment includes selling and administrative expenses, including our technical and shared services functions; results from equity affiliates; corporate hedging activities; trading and brokerage activities; results from certain mining and export/transportation joint ventures; minimum charges on certain transportation-related contracts; the closure of inactive mining sites; and certain commercial matters.
Resource Management. As of December 31, 2020, we controlled approximately 3.0 billion tons of proven and probable coal reserves and approximately 450,000 acres of surface property through ownership and lease agreements. We have an ongoing asset optimization program whereby our property management group regularly reviews these reserves and surface properties for opportunities to generate earnings and cash flow through the sale or exchange of non-strategic coal reserves and surface lands. These surface lands include acres where we have completed post-mining reclamation. In addition, we generate revenue through royalties from coal reserves and oil and gas rights leased to third parties and farm income from surface lands under third-party contracts.
Middlemount Mine. We own a 50% equity interest in Middlemount, which owns the Middlemount Mine in Queensland, Australia. The mine predominantly produces semi-hard coking coal and LV PCI coal for sale into seaborne coal markets through Abbot Point Coal Terminal, with some capacity also secured at Dalrymple Bay Coal Terminal. Mining operations first commenced at the Middlemount Mine in late 2011. During the years ended December 31, 2020, 2019 and 2018, the mine sold 3.2 million, 2.9 million and 4.2 million tons of coal, respectively (on a 100% basis).
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Coronavirus (COVID-19) Pandemic
On March 11, 2020, the COVID-19 outbreak was declared a pandemic by the World Health Organization. The pandemic has resulted in governments around the world implementing stringent measures to help control the spread of the virus, including quarantines, “shelter in place” and “stay at home” orders, travel restrictions, business curtailments, school closures and other measures. In addition, governments and central banks in several parts of the world have enacted fiscal and monetary stimulus measures to counteract the impacts of the COVID-19 pandemic.
Coal mining in the U.S. and Australia has been designated as an essential business to support coal-fueled electric power generation and critical steelmaking needs. As part of Peabody’s commitment to the ongoing health and safety of our employees, vendors and communities, we are following advice from government authorities and taking precautions to manage the spread of COVID-19. Peabody operations have implemented rigorous protocols, control and prevention measures, including mandatory temperature and health checks; paid leave for recommended self-isolation periods; enhanced cleaning and sterilization practices; expanded use of personal protective equipment; social distancing; and working remotely when circumstances warrant. While our operations have been designated as essential, each operation will only continue to operate when it is safe and economic to do so.
The global impact on economic activity has severely curtailed demand for numerous commodities. Within the global coal industry, supply and demand disruptions have been widespread. The global economy is showing improvement in industrial production, even as the timing of a recovery varies across countries and sectors. However, in the seaborne metallurgical and thermal markets, demand remains below pre-pandemic levels. In the U.S., the impacts of COVID-19 have accelerated a multi-year decline in coal demand. During the year ended December 31, 2020, coal-fueled generation declined approximately 20% compared to the prior year period and now represents 19% of the overall generation mix. Additionally, we have faced limited disruption to supply chain and distribution channels and adverse effects to our workforce. Coal industry fundamentals, as well as known impacts specific to Peabody, are further addressed in the “Results of Operations” section contained within this Item 7.
While the ultimate impacts of the COVID-19 pandemic on our business are unknown, we expect continued interference with general commercial activity, which may negatively affect both demand and prices for our products. Given the uncertainties with respect to future COVID-19 developments, including the duration, severity and scope, as well as the necessary government actions to limit the spread, we are unable to estimate the full impact of the pandemic on our business, financial condition, results of operations or cash flows at this time.
On March 27, 2020, the Coronavirus Aid, Relief and Economic Security Act (the CARES Act), a $2 trillion economic relief bill, was enacted in the U.S.. The CARES Act contained numerous income tax provisions, including a provision that provides for the acceleration of refunds of previously generated alternative minimum tax credits. Pursuant to the CARES Act, we received approximately $24 million of accelerated refunds from the Internal Revenue Service and adjusted our current and deferred tax asset balances accordingly. The CARES Act also contained a provision for deferred payment of 2020 employer payroll taxes after the date of enactment to future years. We deferred a portion of our remaining 2020 employer payroll taxes to subsequent years.
North Goonyella Mine
Our North Goonyella Mine in Queensland, Australia experienced a fire in a portion of the mine during September 2018 and mining operations have been suspended since then. In 2020, we commenced a review of strategic alternatives for North Goonyella which is currently ongoing.
During the years ended December 31, 2019 and 2018, we recorded provisions for equipment losses of $83.2 million and $66.4 million, respectively, related to the fire, representing the best estimate of losses to date. No additional provisions for equipment losses were recorded during the year ended December 31, 2020. We have also incurred containment and idling costs subsequent to the mine’s suspension which amounted to $32.3 million, $111.5 million and $58.0 million during the years ended December 31, 2020, 2019 and 2018, respectively.
In March 2019, we entered into an insurance claim settlement agreement with our insurers and various re-insurers under a combined property damage and business interruption policy and recorded a $125 million insurance recovery, the maximum amount available under the policy above a $50 million deductible. We have collected the full amount of the recovery.
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Results of Operations
Non-GAAP Financial Measures
The following discussion of our results of operations includes references to and analysis of Adjusted EBITDA, which is a financial measure not recognized in accordance with U.S. generally accepted accounting principles (U.S. GAAP). Adjusted EBITDA is used by management as the primary metric to measure each of our segments’ operating performance. We have retrospectively modified our calculation of Adjusted EBITDA to exclude restructuring charges and transaction costs related to business combinations and joint ventures as management does not view these items as part of our normal operations.
Also included in the following discussion of our results of operations are references to Revenues per Ton, Costs per Ton and Adjusted EBITDA Margin per Ton for each mining segment. These metrics are used by management to measure each of our mining segments’ operating performance. Management believes Costs per Ton and Adjusted EBITDA Margin per Ton best reflect controllable costs and operating results at the mining segment level. We consider all measures reported on a per ton basis to be operating/statistical measures; however, we include reconciliations of the related non-GAAP financial measures (Adjusted EBITDA and Total Reporting Segment Costs) in the “Reconciliation of Non-GAAP Financial Measures” section contained within this Item 7.
In our discussion of liquidity and capital resources, we include references to Free Cash Flow which is also a non-GAAP measure. Free Cash Flow is used by management as a measure of our financial performance and our ability to generate excess cash flow from our business operations.
We believe non-GAAP performance measures are used by investors to measure our operating performance and lenders to measure our ability to incur and service debt. These measures are not intended to serve as alternatives to U.S. GAAP measures of performance and may not be comparable to similarly-titled measures presented by other companies. Refer to the “Reconciliation of Non-GAAP Financial Measures” section contained within this Item 7 for definitions and reconciliations to the most comparable measures under U.S. GAAP.
Year Ended December 31, 2020 Compared to Year Ended December 31, 2019
Summary
Spot pricing for premium low-vol hard coking coal (Premium HCC), premium low-vol pulverized coal injection (Premium PCI) coal, Newcastle index thermal coal and API 5 thermal coal, and prompt month pricing for PRB 8,880 Btu/Lb coal and Illinois Basin 11,500 Btu/Lb coal during the year ended December 31, 2020 is set forth in the table below.
The seaborne pricing included in the table below is not necessarily indicative of the pricing we realized during the year ended December 31, 2020 due to quality differentials and the majority of our seaborne sales being executed through annual and multi-year international coal supply agreements that contain provisions requiring both parties to renegotiate pricing periodically. Our typical practice is to negotiate pricing for seaborne metallurgical coal contracts on a quarterly, spot or index basis and seaborne thermal coal contracts on an annual, spot or index basis.
In the U.S., the pricing included in the table below is also not necessarily indicative of the pricing we realized during the year ended December 31, 2020 since we generally sell coal under long-term contracts where pricing is determined based on various factors. Such long-term contracts in the U.S. may vary significantly in many respects, including price adjustment features, price reopener terms, coal quality requirements, quantity parameters, permitted sources of supply, treatment of environmental constraints, extension options, force majeure and termination and assignment provisions. Competition from alternative fuels such as natural gas and other fuel sources may also impact our realized pricing.
High Low Average December 31, 2020
(1) Prices expressed per tonne.
(2) Prices expressed per ton.
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Within the global coal industry, supply and demand disruptions have been widespread as the COVID-19 pandemic has forced country-wide lockdowns and regional restrictions. Future COVID-19-related developments are unknown, including the duration, severity, scope and the necessary government actions to limit the spread of COVID-19. The global coal industry data for the year ended December 31, 2020 presented herein may not be indicative of the ultimate impacts of the COVID-19 pandemic given the various levels of response and unknown duration, and potential for continued weak demand for our products.
With respect to seaborne metallurgical coal, global steel production decreased approximately 1% during the year ended December 31, 2020 compared to the prior year, with significant declines in most regions due to the impacts of COVID-19, offset by another year of strong growth in China. Excluding China, steel production was down approximately 10%, while Chinese steel production increased approximately 5% from 2019. While global steel production remained lower year-over-year, there has been consistent improvement in steel production since July 2020 as COVID-19 related lockdown restrictions eased in key countries. Improved steel demand has enabled steelmakers, including Peabody customers, to restart capacity and increase output, resulting in improvements in seaborne metallurgical coal demand. For example, India seaborne metallurgical coal imports set a new all-time monthly volume record each month from October to December. Elsewhere, the recovery continues steadily with most countries operating at or just below pre-COVID-19 levels. A key risk to demand for Australian metallurgical coal in 2021 is China’s import policies, which have largely prohibited the buying of Australian products since October 2020 and an end date to the limitations is currently unclear.
Within the seaborne thermal coal market, demand has been below pre-pandemic levels in many key countries, and headwinds such as COVID-19, China import restrictions and competition from alternative fuel sources persist. China thermal imports were up 6 million tonnes through the year ended December 31, 2020. India has seen domestic power demand recover, but thermal imports are down by approximately 25 million tonnes through the year ended December 31, 2020 compared to the prior year.
In the United States, overall electricity demand has been negatively impacted year-over-year due to COVID-19 induced economic shutdowns and mild weather during the year ended December 31, 2020. The reduction in thermal coal demand during that period has exceeded the reduction in overall electricity demand as continued coal plant retirements, and growth in natural gas and renewable generation negatively impacted coal’s share of electricity generation. Lower total electricity demand driven by COVID-19 related curtailments has resulted in coal’s share of generation declining to approximately 19% for the year ended December 31, 2020, while natural gas and renewables increased. Through the year ended December 31, 2020 utility consumption of PRB coal fell approximately 20% compared to the prior year period.
Our revenues for the year ended December 31, 2020 decreased compared to the same period in 2019 ($1,742.3 million) primarily due to lower sales volumes which were affected by the COVID-19 pandemic and lower realized prices.
Results from continuing operations, net of income taxes for the year ended December 31, 2020 decreased compared to the same period in the prior year ($1,671.5 million). The decrease was driven by the unfavorable revenue variance described above, higher asset impairment charges recorded in the current period ($1,217.2 million) and a prior year insurance recovery related to the events at our North Goonyella Mine ($125.0 million). These unfavorable variances were partially offset by reduced operating costs and expenses owing largely to the sales volume decline as well as production efficiencies and other cost improvements ($1,011.7 million) and lower depreciation, depletion and amortization ($255.0 million).
Adjusted EBITDA for the year ended December 31, 2020 reflected a year-over-year decrease of $624.2 million.
As of December 31, 2020, our available liquidity was approximately $729 million. Refer to the “Liquidity and Capital Resources” section contained within this Item 7 for a further discussion of factors affecting our available liquidity.
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Tons Sold
The following table presents tons sold by operating segment:
(Decrease) Increase
Year Ended December 31, to Volumes
(Tons in millions)
Seaborne Metallurgical Mining 5.6 8.1 (2.5) (30.9) %
Supplemental Financial Data
The following table presents supplemental financial data by operating segment:
Year Ended December 31, (Decrease) Increase
Revenues per Ton - Mining Operations (1)
Costs per Ton - Mining Operations (1) (2)
Adjusted EBITDA Margin per Ton - Mining Operations (1) (2)
(1)This is an operating/statistical measure not recognized in accordance with U.S. GAAP. Refer to the “Reconciliation of Non-GAAP Financial Measures” section below for definitions and reconciliations to the most comparable measures under U.S. GAAP.
(2)Includes revenue-based production taxes and royalties; excludes depreciation, depletion and amortization; asset retirement obligation expenses; selling and administrative expenses; restructuring charges; asset impairment; provision for North Goonyella equipment loss and related insurance recovery; amortization of take-or-pay contract-based intangibles; and certain other costs related to post-mining activities.
(3)Costs incurred at the North Goonyella Mine from January 1, 2020 forward are included within the Corporate and Other segment. Costs incurred at the North Goonyella Mine during the year ended December 31, 2019 remain within the Seaborne Metallurgical Mining segment and resulted in additional Costs per Ton and lower Adjusted EBITDA Margin per Ton of $9.59.
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Revenues
The following table presents revenues by reporting segment:
Decrease
Year Ended December 31, to Revenues
(Dollars in millions)
Seaborne Thermal Mining. The decrease in our Seaborne Thermal Mining segment revenues for the year ended December 31, 2020 compared to the prior year was driven by unfavorable realized coal pricing ($220.3 million) and unfavorable volume and mix variances ($39.6 million).
Seaborne Metallurgical Mining. Segment revenues decreased during the year ended December 31, 2020 compared to the prior year due to unfavorable volume and mix variances ($340.8 million) resulting from demand-based volume decreases across our mines and unfavorable realized coal pricing ($205.8 million).
Powder River Basin Mining. Segment revenues decreased during the year ended December 31, 2020 compared to the prior year period due to demand-based volume decreases ($244.3 million) and the prior year benefit of a contract settlement with a PRB customer ($19.7 million). These unfavorable variances were partially offset by favorable realized coal pricing ($26.4 million).
Other U.S. Thermal Mining. The decrease in segment revenues for the year ended December 31, 2020 compared to the same period in the prior year was primarily due to volume decreases ($453.6 million) which were driven by the closure of the Kayenta and Cottage Grove Mines during the third quarter of 2019 and the Wildcat Hills Underground Mine during the second quarter of 2020, the prior year benefit of revenues associated with the final commercial negotiations for the Kayenta Mine ($127.8 million) and unfavorable realized coal pricing ($20.7 million).
Corporate and Other. Segment revenues decreased during the year ended December 31, 2020 compared to the prior year due to lower results on economic hedge activities.
Adjusted EBITDA
The following table presents Adjusted EBITDA for each of our reporting segments:
(Decrease) Increase to
Year Ended December 31, Adjusted EBITDA
(Dollars in millions)
(1)This is a financial measure not recognized in accordance with U.S. GAAP. Refer to the “Reconciliation of Non-GAAP Financial Measures” section below for definitions and reconciliations to the most comparable measures under U.S. GAAP.
Seaborne Thermal Mining. Segment Adjusted EBITDA decreased during the year ended December 31, 2020 compared to the same period in the prior year as a result of lower realized net coal pricing ($202.4 million), unfavorable volume variances ($12.6 million) and the unfavorable impacts of a temporary shutdown at our Wambo Underground Mine ($12.2 million). The decrease was partially offset by favorable mine sequencing impacts and lower costs for materials, services and repairs at our thermal surface mines ($35.6 million) and lower pricing for fuel ($14.0 million).
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Seaborne Metallurgical Mining. Segment Adjusted EBITDA decreased during the year ended December 31, 2020 compared to the same period in the prior year due to lower realized net coal pricing ($188.0 million), unfavorable volume variances ($138.7 million) and higher costs at our Shoal Creek Mine, including those related to a conveyor upgrade ($51.1 million). These negative variances were partially offset by the inclusion of North Goonyella Mine containment and holding costs within our Corporate and Other segment in the current year ($77.6 million) and lower pricing for fuel ($10.9 million).
Powder River Basin Mining. Segment Adjusted EBITDA decreased during the year ended December 31, 2020 compared to the same period in the prior year due to the impact of lower volumes ($43.6 million), the prior year net benefit of a contract settlement with a PRB customer ($24.0 million) and unfavorable mine sequencing impacts ($22.2 million). These negative variances were partially offset by lower costs for materials, services, repairs and labor ($31.1 million), lower pricing for fuel and explosives ($23.5 million) and higher realized net coal pricing ($6.5 million).
Other U.S. Thermal Mining. Segment Adjusted EBITDA decreased during the year ended December 31, 2020 compared to the same period in the prior year primarily due to the impact of lower volumes ($135.4 million) as described above, the prior year net benefit associated with the final commercial negotiations for the Kayenta Mine ($83.3 million), lower realized net coal pricing ($37.8 million) and unfavorable mine sequencing impacts ($12.9 million). These unfavorable variances were partially offset by lower costs for materials, services, repairs and labor ($42.4 million) and lower pricing for fuel and explosives ($16.8 million).
Corporate and Other Adjusted EBITDA. The following table presents a summary of the components of Corporate and Other Adjusted EBITDA:
(Decrease) Increase
Year Ended December 31, to Income
(Dollars in millions)
(1)Middlemount’s results are before the impact of related changes in deferred tax asset valuation allowance and reserves and amortization of basis difference. Middlemount’s standalone results included (on a 50% attributable basis) aggregate amounts of depreciation, depletion and amortization, asset retirement obligation expenses, net interest expense and income taxes of $29.9 million and $25.1 million during the years ended December 31, 2020 and 2019, respectively.
(2)Includes gains (losses) on certain surplus coal reserve and surface land sales and property management costs and revenues.
(3)Includes trading and brokerage activities, costs associated with post-mining activities, gains (losses) on certain asset disposals, minimum charges on certain transportation-related contracts, costs associated with suspended operations including the North Goonyella Mine and expenses related to our other commercial activities.
(4)North Goonyella costs incurred from January 1, 2020 forward are included within the Corporate and Other segment. Costs incurred prior to January 1, 2020 remain within the Seaborne Metallurgical Mining segment.
The increase in Corporate and Other Adjusted EBITDA during the year ended December 31, 2020 compared to the same period in the prior year was due to lower selling and administrative expenses driven by lower personnel costs; the favorable impact of changes made to one of our postretirement health care benefit plans during the third quarter of 2020 ($14.9 million); resource management gains recorded in the current period ($14.8 million); and favorable corporate hedging results ($10.7 million). These favorable results were partially offset by current year containment and holding costs for our North Goonyella Mine ($32.3 million) and an unfavorable variance in Middlemount’s results due to the continuing impacts of lower sales pricing and a significant change to the mine plan following a highwall failure in mid-2019.
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Loss From Continuing Operations, Net of Income Taxes
The following table presents loss from continuing operations, net of income taxes:
(Decrease) Increase to Income
Year Ended December 31,
(Dollars in millions)
Asset retirement obligation expenses (45.7) (58.4) 12.7 21.7 %
Transaction costs related to joint ventures (23.1) (21.6) (1.5) (6.9) %
Gain on formation of United Wambo Joint Venture — 48.1 (48.1) (100.0) %
Provision for North Goonyella equipment loss — (83.2) 83.2 100.0 %
North Goonyella insurance recovery - equipment — 91.1 (91.1) (100.0) %
Unrealized (losses) gains on economic hedges (29.6) 42.2 (71.8) (170.1) %
Unrealized gains on non-coal trading derivative contracts 7.1 1.2 5.9 491.7 %
Take-or-pay contract-based intangible recognition 8.2 16.6 (8.4) (50.6) %
(1)This is a financial measure not recognized in accordance with U.S. GAAP. Refer to the “Reconciliation of Non-GAAP Financial Measures” section below for definitions and reconciliations to the most comparable measures under U.S. GAAP.
Depreciation, Depletion and Amortization. The following table presents a summary of depreciation, depletion and amortization expense by segment:
Increase (Decrease)
Year Ended December 31, to Income
(Dollars in millions)
Seaborne Thermal Mining $ (88.0) $ (90.7) $ 2.7 3.0 %
Additionally, the following table presents a summary of our weighted-average depletion rate per ton for active mines in each of our mining segments:
Year Ended December 31,
Seaborne Thermal Mining $ 1.90 $ 1.84
Seaborne Metallurgical Mining 2.30 3.09
Powder River Basin Mining 0.50 0.80
Other U.S. Thermal Mining 1.04 1.33
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Depreciation, depletion and amortization expense decreased during the year ended December 31, 2020 compared to the same period in the prior year primarily due to the closure of the Kayenta and Cottage Grove Mines during the third quarter of 2019 and the Millennium and Wildcat Hills Underground Mines during the second quarter of 2020 ($122.7 million), the impact of the asset impairment recorded at the North Antelope Rochelle Mine during the second quarter of 2020 ($52.6 million), decreased depletion driven by lower sales volumes ($22.5 million) and lower amortization of contract based intangibles ($21.8 million). The decrease in the weighted-average depletion rate per ton for the Seaborne Metallurgical Mining segment during the year ended December 31, 2020 compared to the same period in the prior year reflects the volume and mix variances which impacted our revenues as described above. The decrease in the weighted-average depletion rate per ton for the Powder River Basin Mining segment during the year ended December 31, 2020 compared to the same period in the prior year reflects the asset impairment recorded during the second quarter of 2020.
Asset Retirement Obligation Expenses. Asset retirement obligation expenses decreased during the year ended December 31, 2020 compared to the same period in the prior year as the result of favorable revisions to the estimates for our closed mines.
Restructuring Charges. Restructuring charges increased during the year ended December 31, 2020 compared to the same period in the prior year as the result of workforce reductions made across the organization through the use of involuntary and voluntary reductions, as discussed in Note 1. “Summary of Significant Accounting Policies” to the accompanying consolidated financial statements.
Transaction Costs Related to Joint Ventures. The charges recorded during the current and prior year periods related to the proposed PRB Colorado joint venture with Arch Resources, Inc. as further described in Note 20. “Other Events” to the accompanying consolidated financial statements.
Gain on Formation of United Wambo Joint Venture. During the year ended December 31, 2019, we recognized a $48.1 million gain upon the formation of the United Wambo Joint Venture. Refer to Note 20. “Other Events” to the accompanying consolidated financial statements for further information regarding the calculation of the gain, which information is incorporated herein by reference.
Asset Impairment. We recognized $1,487.4 million in aggregate asset impairment charges during the year ended December 31, 2020, primarily related to the fair value of our North Antelope Rochelle Mine in our Powder River Basin Mining segment. During the year ended December 31, 2019, we recognized $270.2 million in aggregate asset impairment charges primarily related to the El Segundo/Lee Ranch and Wildcat Hills Underground Mines in our Other U.S. Thermal Mining segment. Refer to Note 3. “Asset Impairment” to the accompanying consolidated financial statements for further information regarding the nature and composition of those charges, which information is incorporated herein by reference.
Provision for North Goonyella Equipment Loss. A provision for expected equipment losses related to the events at our North Goonyella Mine was recorded during the prior year as discussed in Note 20. “Other Events” to the accompanying consolidated financial statements.
North Goonyella Insurance Recovery - Equipment. During the year ended December 31, 2019, we entered into an insurance claim settlement agreement with our insurance providers related to North Goonyella equipment losses and recorded a $125.0 million insurance recovery, as discussed in Note 20. “Other Events” to the accompanying consolidated financial statements. Of this amount, Adjusted EBITDA excludes an allocated amount applicable to total equipment losses recognized at the time of the insurance recovery settlement, which consisted of $24.7 million and $66.4 million recognized during the years ended December 31, 2019 and 2018, respectively. The remaining $33.9 million, applicable to incremental costs and business interruption losses, is included in Adjusted EBITDA for the year ended December 31, 2019.
Changes in Deferred Tax Asset Valuation Allowance and Reserves and Amortization of Basis Difference Related to Equity Affiliates. During the year ended December 31, 2020, we established a valuation allowance on Middlemount’s net deferred tax position of approximately $33 million. During the year ended December 31, 2019, we released a tax reserve of approximately $17 million. Refer to Note 6. “Equity Method Investments” to the accompanying consolidated financial statements for further information regarding these changes, which information is incorporated herein by reference
Interest Income. The decrease in interest income during the year ended December 31, 2020 compared to the prior year was driven by the conclusion of a contract during the fourth quarter of 2019 which contained an embedded financing element and by lower cash balances.
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Net Mark-to-Market Adjustment on Actuarially Determined Liabilities. The gain recorded during the year ended December 31, 2020 was driven by gains on pension and postretirement benefit plan assets ($73.7 million), the favorable impacts of a mortality update for all actuarially determined liabilities ($39.5 million) and changes related to claims for the postretirement benefit plans ($21.2 million). These increases were offset by decreases to the discount rates for all actuarially determined liabilities ($116.5 million).
The expense recorded during the year ended December 31, 2019 was driven by decreases to the discount rates for all actuarially determined liabilities ($137.6 million) and the unfavorable impact of changes related to claims and an update to our census data for the postretirement benefits plans ($19.7 million). These decreases were partially offset by actuarial gains on pension assets ($94.5 million).
Unrealized (Losses) Gains on Economic Hedges. Unrealized (losses) gains primarily relate to mark-to-market activity from economic hedge activities intended to hedge future coal sales. For additional information, refer to Note 7. “Derivatives and Fair Value Measurements” to the accompanying consolidated financial statements.
Take-or-Pay Contract-Based Intangible Recognition. During the years ended December 31, 2020 and 2019, we ratably recognized contract-based intangible liabilities for port and rail take-or-pay contracts. For additional details, refer to Note 8. “Intangible Contract Assets and Liabilities” to the accompanying consolidated financial statements.
Income Tax Provision. The decrease in the income tax provision during the year ended December 31, 2020 compared to the prior year period was primarily due to year-over-year decreases in taxable income, partially offset by an increase in the provision related to the remeasurement of foreign income tax accounts. Refer to Note 10. “Income Taxes” to the accompanying consolidated financial statements for additional information.
Net Loss Attributable to Common Stockholders
The following table presents net loss attributable to common stockholders:
Decrease to
Year Ended December 31, to Income
(Dollars in millions)
(Loss) Income from Discontinued Operations, Net of Income Taxes. The decrease in results from discontinued operations, net of income taxes during the year ended December 31, 2020 compared to the prior year period was primarily driven by decreases to the discount rates for black lung liabilities.
Net (Loss) Income Attributable to Noncontrolling Interests. The decrease in net results attributable to noncontrolling interests during the year ended December 31, 2020 compared to the prior year period was primarily due to lower results of our majority-owned mines in which there is an outside non-controlling interest.
Diluted EPS
The following table presents diluted EPS:
Decrease to
Year Ended December 31, EPS
Diluted EPS attributable to common stockholders:
(Loss) income from discontinued operations (0.15) 0.03 (0.18) (600.0) %
Diluted EPS is commensurate with the changes in results from continuing operations and discontinued operations during that period. Diluted EPS reflects weighted average diluted common shares outstanding of 97.7 million and 103.7 million for the years ended December 31, 2020 and 2019, respectively.
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Year Ended December 31, 2019 Compared to Year Ended December 31, 2018
Summary
Spot pricing for Premium HCC, Premium PCI coal, Newcastle index thermal coal and API 5 thermal coal, and prompt month pricing for PRB 8,880 Btu/Lb coal and Illinois Basin 11,500 Btu/Lb coal during the year ended December 31, 2019 is set forth in the table below.
The seaborne pricing included in the table below is not necessarily indicative of the pricing we realized during the year ended December 31, 2019 due to quality differentials and the majority of our seaborne sales being executed through annual and multi-year international coal supply agreements that contain provisions requiring both parties to renegotiate pricing periodically. Our typical practice is to negotiate pricing for seaborne metallurgical coal contracts on a quarterly, spot or index basis and seaborne thermal coal contracts on an annual, spot or index basis.
In the U.S., the pricing included in the table below is also not necessarily indicative of the pricing we realized during the year ended December 31, 2019 since we generally sell coal under long-term contracts where pricing is determined based on various factors. Such long-term contracts in the U.S. may vary significantly in many respects, including price adjustment features, price reopener terms, coal quality requirements, quantity parameters, permitted sources of supply, treatment of environmental constraints, extension options, force majeure and termination and assignment provisions. Competition from alternative fuels such as natural gas and other coal producers may also impact our realized pricing.
High Low Average December 31, 2019
(1) Prices expressed per tonne.
(2) Prices expressed per ton.
With respect to seaborne metallurgical coal, global steel production increased approximately 3% through the year ended December 31, 2019 as compared to the prior year period. India imports increased approximately 5% through the year ended December 31, 2019, as compared to the prior year, amid domestic steel production growth of approximately 3% year-over-year. Steel production in China increased approximately 7% through the year ended December 31, 2019 as compared to the prior year, resulting in an approximate 15% increase in coking coal imports during the same period.
Seaborne thermal coal demand and pricing was subdued due to restrictions in China and low gas prices coupled with elevated stockpiles in Europe, despite robust demand from India and other Asian regions. Chinese thermal coal imports increased by approximately 8 million tonnes through the year ended December 31, 2019 as compared to the prior year. Despite constraints by heightened mine safety inspections, China’s domestic production registered a 4.2% increase through the year ended December 31, 2019, as compared to the prior year period, supported by new mine approvals. India’s domestic production declined approximately 1% through the year ended December 31, 2019, which was not sufficient to meet growing demand from its industrial and power sectors. As a result, India’s thermal coal imports increased by approximately 6% or 10 million tonnes year-over-year through December 31, 2019. Demand from countries comprising the Association of Southeast Asian Nations (ASEAN) increased 23 million tonnes through the year ended December 31, 2019 as compared to the prior year, primarily led by Vietnam.
In the United States, overall electricity demand was down year-over-year through the year ended December 31, 2019. Continued coal plant retirements, growth in natural gas and renewable generation and weak natural gas prices negatively impacted coal demand. For the year ended December 31, 2019, utility consumption of PRB coal fell approximately 16% as compared to the prior year due to ongoing pressure from retirements, wind generation and regional natural gas prices that traded at a discount to quoted Henry Hub natural gas spot prices.
Our revenues for the year ended December 31, 2019 decreased as compared to the same period in 2018 ($958.4 million) primarily due to lower sales volumes and realized prices. Our Seaborne Metallurgical Mining segment was adversely impacted by the events at our North Goonyella Mine described above, as well as other production factors, partially offset by the incremental volume provided by our Shoal Creek Mine. Our Powder River Basin Mining segment was adversely impacted by lower demand and delays in rail shipments caused by severe flooding during the first half of 2019.
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Results from continuing operations, net of income taxes for the year ended December 31, 2019 decreased as compared to the same period in the prior year ($834.0 million). The decrease was driven by the unfavorable revenue variances described above, as well as asset impairment charges recorded in the current period ($270.2 million), the impact of a net mark-to-market loss on actuarially determined liabilities as compared to a gain in the prior year ($192.9 million) and approximately $20 million of expense in the current year related to the Monto litigation. These unfavorable variances were partially offset by reduced operating costs and expenses owing largely to the sales volume decline as well as production efficiencies and other cost improvements ($534.8 million) and an insurance recovery related to the events at our North Goonyella Mine ($125.0 million).
The decrease in net results attributable to common stockholders during the year ended December 31, 2019 as compared to the same period in 2018 was partially offset by dividends ($102.5 million) recorded in the prior year period related to the convertible preferred stock issued in connection with our reorganization. Adjusted EBITDA for the year ended December 31, 2019 reflected a year-over-year decrease of $504.9 million.
Tons Sold
The following table presents tons sold by operating segment:
Increase (Decrease)to Tons Sold
Year Ended December 31,
(Tons in millions)
Seaborne Metallurgical Mining 8.1 11.0 (2.9) (26.4) %
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Supplemental Financial Data
The following table presents supplemental financial data by operating segment:
Year Ended December 31, (Decrease) Increase
Revenues per Ton - Mining Operations (1)
Costs per Ton - Mining Operations (1) (2)
Adjusted EBITDA Margin per Ton - Mining Operations (1) (2)
(1)This is an operating/statistical measure not recognized in accordance with U.S. GAAP. Refer to the “Reconciliation of Non-GAAP Financial Measures” section below for definitions and reconciliations to the most comparable measures under U.S. GAAP.
(2)Includes revenue-based production taxes and royalties; excludes depreciation, depletion and amortization; asset retirement obligation expenses; selling and administrative expenses; restructuring charges; asset impairment; provision for North Goonyella equipment loss and related insurance recovery; amortization of take-or-pay contract-based intangibles; and certain other costs related to post-mining activities.
(3)Includes the events at the North Goonyella Mine resulting in additional Costs per Ton and lower Adjusted EBITDA Margin per Ton for Seaborne Metallurgical of $9.59 and $5.27 for the years ended December 31, 2019 and 2018, respectively.
Revenues
The following table presents revenues by reporting segment:
Year Ended December 31, Decrease to Revenues
(Dollars in millions)
Seaborne Thermal Mining. The decrease in our Seaborne Thermal Mining segment revenues for the year ended December 31, 2019 compared to the prior year was primarily driven by unfavorable realized coal pricing ($131.9 million), partially offset by favorable volume and mix variances ($4.4 million).