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Item 1A. Risk Factors.

The Company operates 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 the Company’s business, financial condition, prospects, operating results or cash flows. The following risk factors are not an exhaustive list of the risks associated with the Company’s business. New factors may emerge or changes to these risks could occur that could materially affect its business.

Risks Associated with Peabody’s Operations

The Company’s profitability depends upon the prices it receives for its coal.

The Company operates in a competitive and highly regulated industry that has at times experienced strong headwinds. Current pricing levels of both seaborne and domestic coal products may not be sustainable in the future. Declines in coal prices could materially and adversely affect the Company’s operating results and profitability and the value of its coal reserves and resources.

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Coal prices are dependent upon factors beyond the Company’s 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 the Company’s metallurgical coal contracts;

•weather patterns, severe weather and natural disasters;

•regulatory, administrative and judicial decisions, including those affecting future mining permits and leases;

•competing technologies used to make steel, some of which do not use coal as a manufacturing input, such as electric arc furnaces; 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 the Company’s coal sales by volume during 2022 and 2021, with the vast majority of these sales 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; (v) other sociopolitical views on coal; and (vi) the coal inventories of utilities. Gas-fueled generation has displaced and could 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 in recent years have also reduced the number of new power plants being built. In recent years, these trends have reduced demand for the Company’s coal and the related prices. Lower demand for coal consumed by electric power generators could reduce the volume of thermal coal that the Company sells and the prices that it receives for the thermal coal, thereby reducing its revenue and adversely impacting its earnings and the value of its coal reserves and resources.

The Company produces metallurgical coal that is used in the global steel industry. Metallurgical coal accounted for approximately 32% and 22% of its revenue in 2022 and 2021, respectively. Changes in governmental policies and regulations and changes in the steel industry, including the demand for steel, could reduce the demand for the Company’s metallurgical coal. Lower demand for metallurgical coal in international markets could reduce the amount of metallurgical coal that the Company sells and the prices that it receives for the metallurgical coal, thereby reducing its revenue and adversely impacting its earnings and the value of its coal reserves and resources.

The balance between coal demand and supply, factoring in demand and supply of closely related and competing fuel sources, both domestically and internationally, could materially reduce coal prices and therefore materially reduce the Company’s revenue and profitability. The Company competes with other fuel sources used for electricity generation, such as natural gas, nuclear and renewables. The Company’s 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 the Company’s coal, thereby reducing its revenue and materially and adversely affecting its business and results of operations.

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If a substantial number of the Company’s long-term coal supply agreements, including those with its largest customers, terminate, or if the pricing, volumes or other elements of those agreements materially adjust, its revenue and operating profits could suffer if the Company is unable to find alternate buyers willing to purchase its coal on comparable terms to those in its contracts.

Most of the Company’s sales are made under coal supply agreements, which are important to the stability and profitability of its operations. The execution of a satisfactory coal supply agreement is frequently the basis on which the Company undertakes the development of coal reserves and resources required to be supplied under the contract, particularly in the U.S. For the year ended December 31, 2022, the Company derived 28% of its revenue from coal supply agreements from its five largest customers. Those five customers were supplied primarily from 16 coal supply agreements (excluding trading and brokerage transactions) expiring at various times from 2023 to 2025.

Many of the Company’s coal supply agreements contain provisions that permit the parties to adjust the contract price upward or downward at specified times. The Company 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. The Company may experience reductions in coal prices in new long-term coal supply agreements replacing some of its expiring contracts. Coal supply agreements also typically contain force majeure provisions allowing temporary suspension of performance by the Company 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 the Company amend the agreements to allow for such variation. Most of its coal supply agreements contain provisions requiring the Company 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 the Company’s customers to terminate their contracts in the event of changes in regulations affecting the coal 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, the Company discusses 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 the Company under long-term supply agreements.

The operating profits the Company realizes from coal sold under supply agreements depend on a variety of factors. In addition, price adjustment and other contract provisions may increase its exposure to short-term coal price volatility. If a substantial portion of the Company’s coal supply agreements were modified or terminated, it could be materially adversely affected to the extent that it is unable to find alternate buyers for its coal at the same level of profitability. Prices for coal vary by mining region and country. As a result, the Company cannot predict the future strength of the coal industry overall or by mining region and cannot provide assurance that it 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, the Company’s 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 the Company’s business, and events and conditions that could occur during the course of its mining operations could have a material adverse impact on the Company.

The Company’s mining operations are subject to conditions that can impact the safety of its 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;

•supply chain constraints or unavailability of equipment or parts;

•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 its longwall equipment;

•unexpected maintenance problems; and

•unforeseen delays in implementation of mining technologies that are new to its operations.

The Company maintains 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 its insurance policies in connection with losses associated with these risks.

The Company’s take-or-pay arrangements could unfavorably affect its profitability.

The Company has substantial take-or-pay arrangements with its port access and rail transportation providers, predominately in Australia, totaling $1.4 billion, with terms ranging up to 20 years, that commit the Company to pay a minimum amount for the delivery of coal even if those commitments go unused. The take-or-pay provisions in these contracts sometimes allow the Company to apply amounts paid for subsequent deliveries, but these provisions have limitations and the Company may not be able to apply all such amounts so paid in all cases. Also, the Company may not be able to utilize the amount of capacity for which it has previously paid. Additionally, the Company 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.

The Company may not recover its investments in its mining, exploration and other assets, which may require the Company to recognize impairment charges related to those assets.

The value of the Company’s assets have from time to time been adversely affected by numerous uncertain factors, some of which are beyond its control, including unfavorable changes in the economic environments in which it operates; declining coal-fired electricity generation; lower-than-expected coal pricing; technical and geological operating difficulties; an inability to economically extract its coal reserves and resources; and unanticipated increases in operating costs. These factors may trigger the recognition of additional impairment charges in the future, which could have a substantial impact on the Company’s results of operations.

Because of the volatile and cyclical nature of coal markets, it is reasonably possible that the Company’s current estimates of projected future cash flows from its mining assets may change in the near term, which may result in the need for adjustments to the carrying value of its assets.

The Company’s ability to operate effectively could be impaired if it loses key personnel or fails to attract qualified personnel.

Peabody manages its business with a number of key personnel, the loss of whom could have a material adverse effect on the Company, absent the completion of an orderly transition. In addition, the Company believes that its future success will depend greatly on its continued ability to attract and retain highly skilled and qualified personnel in tight labor markets, particularly personnel with mining experience. Peabody cannot provide assurance that key personnel will continue to be employed by the Company or that it will be able to attract and retain qualified personnel in the future. Failure to retain or attract key personnel could have a material adverse effect on the Company.

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The Company could be negatively affected if it fails to maintain satisfactory labor relations.

As of December 31, 2022, the Company had approximately 5,500 employees (excluding employees that were employed at operations classified as discontinued), which included approximately 4,300 hourly employees. The Company is party to labor agreements with various labor unions that represent certain of its employees. Such labor agreements are negotiated periodically, and, therefore, the Company is subject to the risk that these agreements may not be able to be renewed on reasonably satisfactory terms. Approximately 34% of its hourly employees were represented by organized labor unions and generated approximately 16% of its coal production for the year ended December 31, 2022. Relations with its employees and, where applicable, organized labor are important to the Company’s success. If some or all of its current non-union operations were to become unionized, the Company could incur an increased risk of work stoppages, reduced productivity and higher labor costs. Also, if the Company fails to maintain good relations or successfully negotiate contracts with its employees who are represented by unions, the Company could potentially experience labor disputes, strikes, work stoppages, slowdowns or other disruptions in production that could negatively impact its profitability.

The Company could be adversely affected if it fails to appropriately provide financial assurances for its obligations.

U.S. federal and state laws and Australian laws require the Company to provide financial assurances related to requirements to reclaim lands used for mining; to pay federal and state workers’ compensation, such as black lung liabilities; to provide financial assurances for coal lease obligations; and to satisfy other miscellaneous obligations. The primary methods the Company uses to meet those obligations are to provide a third-party surety bond or a letter of credit. As of December 31, 2022, the Company had $1,376.8 million of outstanding surety bonds and $569.6 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, in addition to collateral for sureties.

The Company’s 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 the Company, 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 its mines reside. The Company’s 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 it. That failure could result from a variety of factors including:

•lack of availability, higher expense or unfavorable market terms of new surety bonds, bank guarantees or letters of credit;

•inability to provide or fund collateral for current and future third-party issuers of surety bonds, bank guarantees or letters of credit; and

•lack of available fronting banks in certain countries where the Company must provide financial assurances but its primary surety providers are not licensed or admitted.

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,” in November 2020, the Company entered into a surety transaction support agreement with the providers of its surety bond portfolio. The Company’s failure to provide adequate collateral, or abide by other terms in the agreement, could invalidate the agreement and materially and adversely affect its business and results of operations.

The Company’s failure to maintain adequate bonding would invalidate its mining permits and prevent mining operations from continuing, which could result in its inability to continue as a going concern.

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The Company’s mining operations are extensively regulated, which imposes significant costs on it, and future regulations and developments could increase those costs or limit its 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 the Company’s mines, its production and sale of coal would be disrupted and it may be required to incur cash outlays to re-open the mine. Any of these actions could have a material adverse effect on the Company’s financial condition, results of operations and cash flows.

New legislation, regulations or orders related to the environment or employee health and safety may be adopted and may materially adversely affect the Company’s mining operations, its cost structure or its 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 the Company or its customers to change operations significantly or incur increased costs. Some of the Company’s 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 the Company’s financial condition and results of operations.

For additional information about the various regulations affecting the Company, see the sections entitled “Regulatory Matters—U.S.” and “Regulatory Matters —Australia.”

The Company’s operations may impact the environment or cause exposure to hazardous substances, and its properties may have environmental contamination, which could result in material liabilities to the Company.

The Company’s operations currently use hazardous materials and generate limited quantities of hazardous wastes from time to time. A number of laws, including CERCLA and RCRA in the U.S. and similar laws in other countries where the Company operates, 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.

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The Company may be unable to obtain, renew or maintain permits necessary for its operations, or the Company may be unable to obtain, renew or maintain such permits without conditions on the manner in which it runs its operations, which would reduce its production, cash flows and profitability.

Numerous governmental 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 the Company applies for permits and approvals, it is 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, the Company’s operations may be affected by sites within or near mining areas that have cultural heritage significance to indigenous peoples, and its mining permits may be rescinded or modified, or its 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 the Company’s 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 the Company’s ability to efficiently and economically conduct its mining activities, any of which would materially reduce its production, cash flows and profitability.

Concerns about the impacts of coal combustion on global climate are increasingly leading to conditions that have affected and could continue to affect demand for the Company’s products or its securities and its 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, including 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.

The enactment of future laws or the passage of regulations 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-fueled power stations could adversely impact the global demand for coal in the future. The potential financial impact on Peabody 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. 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 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, the Company’s board of directors and management attempt to analyze the potential impact on the Company of as-yet-unadopted, potential laws, regulations and policies. Such analyses require 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 the Company’s operations, financial condition or cash flows. Such analyses cannot be relied upon to reasonably predict the quantitative impact that future laws, regulations or other policies may have on the Company’s results of operations, financial condition or cash flows.

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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 the Company’s 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 the Company’s business. These cost increases and/or substantial or extended declines in the prices the Company receives for its coal due to these or other factors could reduce its revenue and profitability, cash flows, liquidity, and value of its coal reserves and resources, and could result in material losses.

The Company’s trading and hedging activities do not cover certain risks and may expose it to earnings volatility and other risks.

In addition to coal price volatility, the Company is currently subject to price volatility on diesel fuel utilized in its mining operations and the Australian dollar. The Company has entered into certain hedging arrangements to address these risks, and may continue in the future to enter into hedging arrangements, including economic hedging arrangements, to manage these risks or other exposures. Since the Company’s existing hedging arrangements do not receive cash flow hedge accounting treatment, all changes in fair value are reflected in current earnings.

Some of these hedging arrangements may require the Company to post margin based on the value of the related instruments and other credit factors. If the fair value of its hedge portfolio moves significantly, or if laws, regulations or exchange rules are passed requiring all hedge arrangements to be exchange-traded or exchange-cleared, the Company could be required to post additional margin, which could negatively impact its liquidity.

If the assumptions underlying the Company’s asset retirement obligations for reclamation and mine closures are materially inaccurate, its costs could be significantly greater than anticipated.

The Company’s 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. The Company’s management and engineers periodically review these estimates. If its assumptions do not materialize as expected, actual cash expenditures and costs that the Company incurs could be materially different than currently estimated. Moreover, regulatory changes could increase the Company’s 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 its assumptions, which could have a material adverse effect on its results of operations and financial condition.

The Company’s future success depends upon its ability to continue acquiring and developing coal reserves and resources that are economically recoverable.

The Company’s recoverable reserves and resources decline as it produces coal. The Company has not yet applied for the permits required or developed the mines necessary to use all of its reserves and resources. Moreover, the amount of coal reserves and resources described in Part I, Item 2. “Properties” involves the use of certain estimates and those estimates could be inaccurate. Actual production, revenue and expenditures with respect to its coal reserves and resources may vary materially from estimates.

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The Company’s future success depends upon it conducting successful exploration and development activities or acquiring properties containing economically recoverable reserves and resources. The Company’s current strategy includes increasing its reserves and resources through acquisitions of government and other leases and producing properties and continuing to use its existing properties and infrastructure. In certain locations, leases for oil, natural gas and coalbed methane reserves are located on, or adjacent to, some of the Company’s reserves and resources, potentially creating conflicting interests between it and lessees of those interests. Other lessees’ rights relating to these mineral interests could prevent, delay or increase the cost of developing the Company’s coal reserves and resources. These lessees may also seek damages from the Company based on claims that its 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, 2022, the Company leased a total of 44,287 acres from the federal government subject to those limitations.

The Company’s planned mine development projects and acquisition activities may not result in significant additional reserves and resources, and it may not have success developing additional mines. Most of its mining operations are conducted on properties owned or leased by the Company. Its right to mine some of its reserves and resources may be materially adversely affected if defects in title or boundaries exist. In order to conduct its mining operations on properties where these defects exist, the Company may incur unanticipated costs. In addition, in order to develop its reserves and resources, the Company must also own the rights to the related surface property and receive various governmental permits. The Company cannot predict whether it will continue to receive the permits or appropriate land access necessary for it to operate profitably in the future. The Company 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 and resources or maintain its 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, the Company has experienced litigation with lessors of its coal properties and with royalty holders. In addition, from time to time, its permit applications and federal and state coal leases have been challenged, causing production delays.

To the extent that the Company’s existing sources of liquidity are not sufficient to fund its planned mine development projects or reserve and resource acquisition activities, it may require access to capital markets, which may not be available to it or, if available, may not be available on satisfactory terms. If the Company is unable to fund these activities, it may not be able to maintain or increase its existing production rates and could be forced to change its business strategy, which could have a material adverse effect on its financial condition, results of operations and cash flows.

The Company faces numerous uncertainties in estimating its coal reserves and resources and inaccuracies in its estimates could result in lower than expected revenue, higher than expected costs and decreased profitability.

Coal is economically recoverable when the price at which the Company’s 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 its coal is economically recoverable varies based on the mine. Forecasts of the Company’s future performance are based on, among other things, estimates of its recoverable coal reserves and resources. The Company bases its reserve and resource information on engineering, economic and geological data assembled and analyzed by its staff and third parties, which includes various engineers and geologists. The Company's estimates are also subject to SEC regulations regarding classification of reserves and resources, including subpart 1300 of Regulation S-K. The reserve and resource estimates as to both quantity and quality are updated from time to time to reflect production of coal from the reserves and resources 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 and resources, including many factors beyond the Company’s control.

Estimates of economically recoverable coal reserves and resources 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 the Company’s experience in areas it currently mines;

•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.

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The conversion of reported mineral resources to mineral reserves should not be assumed, and the reclassification of reported mineral resources from lower to higher levels of geological confidence should not be assumed. As such, actual coal tonnage recovered from identified reserve and resource areas or properties and revenue and expenditures with respect to the Company’s reserves and resources may vary materially from estimates. Thus, these estimates may not accurately reflect its actual reserves and resources. Any material inaccuracy in the Company’s estimates related to its reserves and resources could result in lower than expected revenue, higher than expected costs or decreased profitability which could materially and adversely affect its business, results of operations, financial position and cash flows.

Joint ventures, partnerships or non-managed operations may not be successful and may not comply with the Company’s operating standards.

The Company participates in several joint venture and partnership arrangements and may enter into others, all of which necessarily involve risk. Whether or not the Company holds majority interests or maintains operational control in its joint ventures, its partners may, among other things, (1) have economic or business interests or goals that are inconsistent with, or opposed to, the Company’s; (2) seek to block actions that the Company believes are in its 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 the Company’s results of operations and its liquidity or impair its ability to recover its investments.

Where the Company’s joint ventures are jointly controlled or not managed by it, the Company may provide expertise and advice but have limited control over compliance with its operational standards. The Company also utilizes contractors across its mining platform, and may be similarly limited in its ability to control their operational practices. Failure by non-controlled joint venture partners or contractors to adhere to operational standards that are equivalent to the Company’s could unfavorably affect safety results, operating costs and productivity and adversely impact its results of operations and reputation.

The Company’s expenditures for postretirement benefit obligations could be materially higher than it has predicted if its underlying assumptions prove to be incorrect.

The Company pays postretirement health and life insurance benefits to eligible retirees. Its total accumulated postretirement benefit obligation related to such benefits was a liability of $172.5 million as of December 31, 2022, of which $16.0 million was classified as a current liability.

These liabilities are actuarially determined. The Company uses various actuarial assumptions, including the discount rate, future cost trends, mortality tables, demographic assumptions and expected rates of return on plan assets to estimate the costs and obligations for these items. Its discount rate is determined by utilizing a hypothetical bond portfolio model which approximates the future cash flows necessary to service its liabilities. A decrease in the discount rate used to determine its 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. The Company has made assumptions related to future trends for medical care costs in the estimates of retiree health care obligations. Its medical trend assumption is developed by annually examining the historical trend of its cost per claim data. If the Company’s assumptions do not materialize as expected, actual cash expenditures and costs that it incurs could differ materially from its current estimates. Moreover, regulatory changes or changes in healthcare benefits provided by the government could increase its obligation to satisfy these or additional obligations. The Company develops its actuarial determinations of liabilities using actuarial mortality tables it believes best fit its population’s actual results. In deciding which mortality tables to use, the Company periodically reviews its population’s actual mortality experience and evaluates results against its 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 its year end valuations. If the Company’s mortality tables do not anticipate its population’s mortality experience as accurately as expected, actual cash expenditures and costs that the Company incurs could differ materially from its current estimates. Additionally, the Company’s reported defined benefit pension funding status may be affected, and it may be required to increase employer contributions, due to increases in its defined benefit pension obligation or poor financial performance in asset markets in future years.

Inflation could result in higher costs and decreased profitability

Recent inflation, increasing the cost of materials, labor, equipment, freight, fuel and other cost categories, has adversely impacted the Company and could be a sustained trend. The Company’s efforts to recover inflation-based cost increases from its customers may be hampered as a result of the structure of its contracts and the contract bidding process as well as the competitive industries, economic conditions and countries in which the Company operates. Accordingly, substantial inflation may result in a material adverse impact on the Company’s costs, profitability and financial results.

During the year ended December 31, 2022, the Company estimates that the impact of inflation increased operating costs and expenses by approximately $230 million over the prior year.

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The Company’s business, results of operations, financial condition and prospects could be materially and adversely affected by pandemic or other widespread illnesses and the related effects on public health.

The Company’s operations are susceptible to widespread outbreaks of illness or other public health issues, such as the global coronavirus (COVID-19) pandemic. Pandemic illnesses could have a material adverse effect on the Company’s business, results of operations, financial condition and prospects, including its ability to comply with restrictions and covenants under its debt and surety bonding obligations.

Governmental mandates and the Company’s efforts to act in the best interests of its employees, customers, suppliers, vendors and joint venture and other business partners, could affect its business and operations, causing the Company to modify a number of its normal business practices. Governmental mandates could require forced shutdowns of its mines and other facilities for extended or indefinite periods and widespread outbreaks in locations significant to its operations could adversely affect its workforce, resulting in serious health issues and absenteeism. In addition, pandemic illnesses could cause supply chain and distribution channels to be interrupted, slowed or rendered inoperable. If the Company’s operations were curtailed, it 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 its customers. Further, if the Company’s customers’ businesses were similarly affected, they might delay, reduce or cancel purchases from the Company. Adverse changes in the general domestic and global economic conditions and disrupted domestic and international credit markets, could negatively affect its customers’ ability to pay the Company as well as its ability to access capital that could negatively affect its liquidity.

Despite its efforts to manage these potential impacts, their ultimate impact would also depend on factors beyond the Company’s knowledge or control, including the duration and severity of the pandemic as well as third-party actions taken to contain its spread and mitigate its public health effects. The Company could also face disruption to supply chain and distribution channels, potentially increasing costs of production, storage and distribution, and potential adverse effects to its workforce, each of which could have a material adverse effect on its business, financial condition, results of operations and prospects.

Peabody is exposed to risks associated with political or international conflicts such as the ongoing conflict between Russia and Ukraine.

Political or international conflicts can result in worldwide geopolitical and macroeconomic uncertainty, as has been the case with the ongoing conflict between Russia and Ukraine. The Company is unable to predict the ultimate impacts related to such conflicts. If a conflict continues for a significant time or expands to other countries, it could have adverse effects on macroeconomic conditions, including but not limited to, turbulent coal pricing and trade flow disruptions resulting from sanctions imposed on coal imports; supply chain disruptions; increased costs; and decreased business spending. Furthermore, political or international conflicts could give rise to disruptions to Peabody or its business partners’ global technology infrastructure, including through cyber attack or cyber intrusion; adverse changes in international trade policies and relations; regulatory enforcement; Peabody’s ability to implement and execute its business strategy; terrorist activities; Peabody’s exposure to foreign currency fluctuations; and constraints, volatility, or disruption in the capital markets, any of which could have a material adverse effect on the Company’s business, results of operations, cash flows and financial condition.

Peabody could be exposed to significant liability, reputational harm, loss of revenue, increased costs or other risks if it sustains cyber attacks or other security breaches that disrupt its operations or result in the dissemination of proprietary or confidential information about the Company, its customers or other third-parties.

Peabody has implemented security protocols and systems with the intent of maintaining the physical security of its operations and protecting the Company’s and its counterparties’ confidential information and information related to identifiable individuals against unauthorized access. Despite such efforts, the Company may be subject to security breaches which could result in unauthorized access to its facilities or the information it is trying to protect. Unauthorized physical access to one of the Company’s facilities or electronic access to its information systems could result in, among other things, unfavorable publicity, litigation by affected parties, damage to sources of competitive advantage, disruptions to its operations, loss of customers, financial obligations for damages related to the theft or misuse of such information and costs to remediate such security vulnerabilities, any of which could have a substantial impact on the Company’s results of operations, financial condition or cash flows.

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The Company is subject to various general operating risks which may be fully or partially outside of its control.

The Company’s 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 its control. Such risks stem from internal and external sources and include:

•global economic recessions and/or credit market disruptions;

•deterioration of the creditworthiness of its 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 the Company;

•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;

•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; and

•uncertainties associated with the Company’s global operating platform, including country and political risks, international regulatory requirements, and foreign currency rates.

Risks Related to Peabody’s Capital Structure

The terms of the agreements and instruments governing the Company’s debt and surety bonding obligations impose restrictions that may limit its operating and financial flexibility.

The agreements governing the Company’s debt and surety bonding obligations contain certain restrictions and covenants which restrict its 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 the Company’s ability to operate its business, as well as significantly affect its liquidity, and therefore could adversely affect its results of operations.

These restrictions and covenants limit, among other things, the Company’s 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 or other 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 its assets; and

•receive dividends or other payments from subsidiaries in certain cases.

The Company’s ability to comply with these restrictions or covenants may be affected by events beyond its control and the Company may need to refinance existing debt in the future. A breach of any of these restrictions or covenants together with the expiration of any cure period, if applicable, could result in a default. If any such default occurs, subject to applicable grace periods, the holders of the Company’s indebtedness may elect to declare such indebtedness, together with accrued interest and other amounts payable thereunder, to be immediately due and payable. If such obligations were to be accelerated, the Company’s financial resources may be insufficient to repay the debt and any other obligations becoming due in full as a result of certain cross default provisions.

If the Company experiences a default under the terms of its debt or surety bonding obligations for any reason, its business, financial condition and results of operations could be materially and adversely affected. In addition, complying with such terms may make it more difficult for the Company to successfully execute its business strategy and compete against companies who are not subject to such restrictions.

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The number and quantity of viable financing and insurance alternatives available to the Company 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 its efforts with respect to environmental and social matters and related governance considerations could harm the perception of the Company by a significant number of investors or result in the exclusion of its 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 the Company’s ability to access capital and financial markets in the future;

•reducing the demand and price for its equity securities;

•increasing the cost of borrowing;

•causing a decline in the Company’s credit ratings;

•reducing the availability, and/or increasing the cost of, third-party insurance;

•increasing the Company’s retention of risk through self-insurance;

•making it more difficult to obtain surety bonds, letters of credit, bank guarantees or other financing; and

•limiting the Company’s flexibility in business development activities such as mergers, acquisitions and divestitures.

Risks Related to Ownership of Peabody’s Securities

The price of Peabody’s securities may be volatile.

The price of Peabody’s common stock (Common Stock) may fluctuate due to a variety of market and industry factors that may materially reduce the market price of its Common Stock regardless of its operating performance, including, among others:

•actual or anticipated fluctuations in Peabody’s quarterly and annual results and those of other public companies in its 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 Peabody or to accurately predict the results it actually achieves;

•changes in accounting principles;

•announcements concerning Peabody or its competitors;

•the purchase and sale of shares of its Common Stock by significant shareholders;

•lack of or excess of trading liquidity; and

•the general volatility of securities markets.

As a result of all of these factors, investors in Peabody’s Common Stock may not be able to resell their stock at or above the price they paid or at all. Further, Peabody 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 its results of operation.

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Peabody’s Common Stock is subject to dilution and may be subject to further dilution in the future.

Peabody’s Common Stock is subject to dilution from its convertible senior debt and its long-term incentive plan. In addition, Peabody may continue issuing 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 the Company’s other stakeholders. A significant stockholder may exert substantial influence over the Company to cause the Company 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 Peabody 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 Peabody or other holders of its Common Stock or debt instruments.

The future payment of dividends on Peabody’s stock or future repurchases of its stock is dependent on a number of factors and 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,” restrictive covenants in the Company’s credit and surety agreements limit its 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 Peabody’s earnings, economic conditions, liquidity and capital requirements, and other factors, including its leverage and other financial ratios. Accordingly, the Company cannot make any assurance that future dividends will be paid or future repurchases will be made.

General Risk Factors

The Company may not be able to fully utilize its deferred tax assets.

The Company is subject to income and other taxes in the U.S. and numerous foreign jurisdictions, most significantly Australia. As of December 31, 2022, the Company had gross deferred income tax assets, including net operating loss (NOL) carryforwards, and liabilities of $1,587.0 million and $81.7 million, respectively, as described further in Note 8. “Income Taxes” to the accompanying consolidated financial statements. At that date, the Company also had recorded a valuation allowance of $1,451.0 million.

The Company’s ability to use its U.S. NOL carryforwards may be limited if it experiences an “ownership change” as defined in 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 the Company may be able to utilize some or all of those deferred tax assets in the future if it has income of the appropriate character in those jurisdictions (subject to loss carryforward and tax credit expiry, in certain cases), there is no assurance that it will be able to do so. Further, the Company is presently unable to record tax benefits on future losses in the U.S. until such time as sufficient income is generated by its operations in those jurisdictions to support the realization of the related net deferred tax asset positions. The Company’s results of operations, financial condition and cash flows may adversely be affected in future periods by these limitations.

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Acquisitions and divestitures are a potentially important part of the Company’s long-term strategy, subject to its investment criteria, and involve a number of risks, any of which could cause the Company not to realize the anticipated benefits.

The Company may engage in acquisition or divestiture activity based on its set of investment criteria to produce outcomes that increase shareholder value or provide potential strategic benefits. If the Company fails 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 it acquires, its business, financial condition or results of operations could be negatively affected. Moreover, any transactions the Company pursues could materially impact its liquidity and an acquisition could increase capital resource needs and may require it to incur indebtedness, seek equity capital or both. The Company 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 its assuming significant long-term liabilities, including potentially unknown liabilities, relative to the value of the acquisitions.

Peabody’s certificate of incorporation and by-laws include provisions that may discourage a takeover attempt.

Provisions contained in Peabody’s certificate of incorporation and by-laws and Delaware law could make it more difficult for a third-party to acquire it, even if doing so might be beneficial to its stockholders. Provisions of Peabody’s 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 its 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 the Company’s reported financial results.

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

Item 1B. Unresolved Staff Comments.

None.

Item 2. Properties.

Coal Reserves and Resources

Information concerning the Company’s mining properties in this Annual Report on Form 10-K has been prepared in accordance with the requirements of subpart 1300 of Regulation S-K, which first became applicable to the Company for the year ended December 31, 2021. These requirements differ significantly from the previously applicable disclosure requirements of SEC Industry Guide 7. Among other differences, subpart 1300 of Regulation S-K requires disclosure of mineral resources, in addition to mineral reserves, both in the aggregate and for each of the Company’s individually material mining properties. The Company’s coal reserves and resources are estimated by individuals deemed Qualified Persons (QP) according to the standards set forth in subpart 1300 of Regulation S-K.

Mineral resources and reserves are defined in subpart 1300 of Regulation S-K as follows:

•Mineral resource. A concentration or occurrence of material of economic interest in or on the earth's crust in such form, grade or quality, and quantity that there are reasonable prospects for economic extraction. A mineral resource is a reasonable estimate of mineralization, taking into account relevant factors such as cut-off grade, likely mining dimensions, location or continuity, that, with the assumed and justifiable technical and economic conditions, is likely to, in whole or in part, become economically extractable. It is not merely an inventory of all mineralization drilled or sampled.

•Mineral reserve. An estimate of tonnage and grade or quality of indicated and measured mineral resources that, in the opinion of a QP, can be the basis of an economically viable project. More specifically, it is the economically mineable part of a measured or indicated mineral resource, which includes diluting materials and allowances for losses that may occur when the material is mined or extracted.

Under subpart 1300 of Regulation S-K, mineral resources may not be classified as mineral reserves unless the determination has been made by a QP that such mineral resources can be the basis of an economically viable project. The conversion of reported mineral resources to mineral reserves should not be assumed.

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Coal resources are estimated from geological models constructed from an extensive historical database of drill holes and the Company’s ongoing drilling program. Data from individual drill holes is compiled in a computerized drill-hole database, including the depth, thickness and, where core drilling is used, the quality of the coal observed. For coal deposits, the density of a drill pattern is one of the important factors which determine whether the related coal will be classified as measured, indicated, or inferred.

Mineral resource classifications are differentiated under subpart 1300 of Regulation S-K, in part, as follows:

•Measured resource. That part of a mineral resource with the highest level of geological confidence; quantity and grade or quality are estimated on the basis of conclusive geological evidence and sampling. The level of geological certainty associated with a measured mineral resource is sufficient to allow a qualified person to apply modifying factors in sufficient detail to support detailed mine planning and final evaluation of the economic viability of the deposit.

•Indicated resource. That part of a mineral resource with a level of geological confidence between that of measured and inferred resources; quantity and grade or quality are estimated on the basis of adequate geological evidence and sampling. The level of geological certainty associated with an indicated mineral resource is sufficient to allow a qualified person to apply modifying factors in sufficient detail to support mine planning and evaluation of the economic viability of the deposit.

•Inferred resource. That part of a mineral resource with the lowest level of geological confidence; quantity and grade or quality are estimated on the basis of limited geological evidence and sampling. The level of geological uncertainty associated with an inferred mineral resource is too high to apply relevant technical and economic factors likely to influence the prospects of economic extraction in a manner useful for evaluation of economic viability.

The geological confidence surrounding resource classification is first determined by a drill hole spacing analysis performed by a QP using geostatistical techniques. A QP may also use qualitative analysis to determine the geologic confidence based on historical experience with a specific coal deposit. Resources are further evaluated using a set of structure and quality parameters to determine the reasonable prospects for economic extraction. The structure parameters include coal thickness, depth, dipping angle, and strip ratio, among others. The quality parameters include ash and sulfur content, yield, and heat value, among others. Each coal deposit is different with respect to geology, potential mining methods, logistics, and markets. The cut-off criteria of those structure and quality parameters are different for each deposit, and a QP generally forms those criteria based upon experience with the Company’s existing mining operations or adjacent operations with similar geological conditions. Other factors, such as coal control, or surface and underground obstacles are also considered in connection with resource estimates. The reclassification of reported mineral resources from lower to higher levels of geological confidence should not be assumed.

The economically mineable part of a measured coal resource is considered a proven coal reserve and has the highest degree of assurance of economic viability. The economically mineable part of indicated, and sometimes measured, coal resources are considered probable coal reserves and have a moderate degree of assurance of economic viability.

For each mine or future mine, the Company develops Life-of-Mine (LOM) plans which employ a market-driven, risk-adjusted capital allocation process to guide long-term mine planning of active operations and development projects. QPs rely on LOM planning as an integral process for coal reserve and resource estimates. The LOM plans consider dilution and losses during mining and processing as recoverability factors to estimate saleable coal. The LOM plans are developed in consideration of market demands and operational constraints. The LOM plans project, 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 and sales prices. 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 viable coal in the LOM plans. Other factors impacting the 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 Company periodically reviews and updates coal reserve and resource estimates to reflect the production of coal, new drill hole data, the effects of mining activities, analysis of new engineering and geological data, changes in property control, modification of mining methods and other factors.

Mineral Rights

The Company controls coal rights through direct ownership and numerous lease agreements with government or private parties. The majority of the Company’s coal reserves and resources are controlled through lease agreements with the U.S. and Australian governments. In addition, surface rights are required to conduct certain mining-related activities. The Company holds the majority of the required surface rights to meet mid- to long-term production requirements. The additional surface rights to meet long-term production requirements are expected to be acquired as needed.

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The Company is party to 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 Peabody’s principal reserves in the Powder River Basin and other reserves and resources 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 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, 2022, the Company leased 1,610 acres of federal land in Alabama, 3,480 acres in Colorado, 282 acres in New Mexico and 38,915 acres in Wyoming, for a total of 44,287 acres nationwide subject to those limitations. The Company 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 the Company 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 private 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 private U.S. leases are normally extended by active production at or near the end of the lease term. Private U.S. leases containing undeveloped coal properties may expire or these leases may be renewed periodically.

Mining and exploration in Australia are 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.

Pricing

The pricing information used in support of the Company’s reserve and resource estimates include internal, proprietary price forecasts and existing contract economics, in each case on a mine-by-mine and product-by-product basis. In general, 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 supply and demand fundamentals for steel production and electricity generation, 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 the Company) to confirm the conclusions reached through analytical processes, and that 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 the Company evaluates in developing 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 the price forecasts and realized factors could cause actual pricing to differ from the 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 and economic activity, 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 coal reserve and resource 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.

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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 the 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 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 used to establish LOM plans are generally made 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. 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 Company’s operating costs include:

•Geological settings. The geological characteristics of each mine are among the most important factors that determine the mining cost. Company geologists conduct the exploration program and provide 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, dragline systems generally have a lower unit cost than truck-and-shovel systems for overburden removal. Longwall operations are generally 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 control represents a significant cost. Forecasted commodity prices are used to project those costs in the financial models used to establish reserve and resource estimates.

•Target product quality. By targeting a premium quality product, 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 the Company’s LOM plans, product qualities are estimated to correspond to existing contracts and forecasted market demands.

•Transportation costs. Transportation costs vary by region. Most of the Company’s U.S. thermal operations sell coal at mine loadouts. Therefore, no transportation expenses are included in U.S. thermal cost estimates. The Company’s seaborne operations typically sell coal at designated ports. The estimated costs for seaborne operations include rail and barge transportation and related fees at ports.

•Royalty costs. 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 the Company’s Australian production are predominantly denominated in Australian dollars, while the Australian coal exported is sold in U.S. dollars. As a result, Australian/U.S. dollar exchange rates impact the U.S. dollar cost of Australian production.

Summary of Coal Reserves and Resources

Peabody controlled an estimated 2.4 billion tons of coal reserves and 2.4 billion tons of coal resources as of December 31, 2022. Approximately 95% of the Company’s coal reserves and 98% of the Company’s coal resources are held under lease, and the remainder is held through fee ownership.

The following tables summarize the Company’s estimated coal reserves and resources as of December 31, 2021. The quantity of the coal resources is estimated on an in situ basis as attributable to Peabody. Coal resources are reported exclusive of coal reserves. The quantity of the coal reserves is estimated on a saleable product basis as attributable to Peabody. The coal reserves and resources are reported on selected key quality parameters and on different moisture bases generally referenced by sales contracts for each mining property.

Peabody Energy Corporation 2022 Form 10-K 45

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SUMMARY COAL RESERVES AT END OF THE FISCAL YEAR ENDED DECEMBER 31, 2022 (1)

(Tons in millions)

Peabody

Stage Mining Method Coal Type

P Producing S Surface Mine T Thermal

I Idle U Underground Mine C Coking

D Development P Pulverized Coal Injection

E Exploration

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SUMMARY COAL RESOURCES AT END OF THE FISCAL YEAR ENDED DECEMBER 31, 2022 (1)

(Tons in millions)

Measured and Indicated Peabody

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Individual Property Disclosure

To determine the Company’s individually material mining operations in accordance with subpart 1300 of Regulation S-K, management considered both quantitative and qualitative factors, assessed in the context of the Company’s overall business and financial condition. Such assessment included the Company’s aggregate mining operations on all of its mining properties, regardless of the stage of production or the type of coal produced. Quantitative factors included, among others, mining operations’ relative contributions to the Company’s aggregate historical and estimated revenue, cash flows, and Adjusted EBITDA (as defined in Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”) Qualitative factors may include, as applicable, strategic priorities, the regulatory environment, capital expansion plans, and the long-term pricing outlook. The Company concluded that, as of December 31, 2021, its individually material mines are North Antelope Rochelle Mine (NARM), Shoal Creek Mine, Wilpinjong Mine, and the Coppabella-Moorvale Joint Venture. The Company also assesses material changes in the material properties mainly on the basis of the amount of reserves and resources over a period of three years. The Company concluded that, as of December 31, 2022, its material mining operations had no material changes. The Company will update its assessment of individually material mines on an annual basis.

The information that follows relating to such individually material mines is derived, for the most part, from, and in some instances is an extract from, the studies relating to such properties prepared in compliance with the Item 601(b)(96) and subpart 1300 of Regulation S-K. Portions of the following information are based on assumptions, qualifications and procedures that are not fully described herein. The changes from the previous year are not material and no updates for TRS are included in this filing. Other technical details regarding the individual properties should be referred to the previously disclosed TRS.

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North Antelope Rochelle Mine

The North Antelope Rochelle Mine (NARM) is a production-stage surface coal mine located sixty-five miles south of Gillette, Wyoming, USA. NARM is situated in the Gillette Coal Field on the east flank of the Powder River Basin. NARM began operations in 1999 after Peabody combined its interests in the formerly separate North Antelope Mine and Rochelle Mine.

NARM extracts coal from the Wyodak-Anderson coal seam, which ranges from 60- to 80-feet thick and lies from 100 to 400 feet below the surface in the mining area. The Company has secured mineral rights through Federal and State lease agreements which cover 30,159 acres. The typical royalty rate for Federal and State coal leases is 12.5% of realized revenue. Generally, the leases continue indefinitely with periodic renewal, provided there is diligent coal production or other development within the lease area. As of December 31, 2022, all required licenses and permits were in place for the operations of NARM.

The mining operation consists of multiple open pits in four main mining areas, which allows for quality blending and other optimization strategies. Overburden is removed by dragline, truck and shovel, dozer and cast blasting methods. Coal is hauled by truck to one of five dump locations, where it is then crushed and conveyed to silos adjacent to rail load-outs for customer delivery. Coals of varying characteristics may be blended at a central blending facility along the loadout rail loop. Coal is sold unwashed, as a run-of-mine (ROM) product. NARM coal is well recognized for domestic thermal power generation.

The key supporting infrastructure for NARM includes rail services provided by the BNSF Railway Company and Union Pacific Corporation, road access via interstate and state highways and roads, electrical power from a dedicated substation with 230kV and 69kV transmission lines, and water supply from a mine dewatering system and deep wells. The mining industry in the Powder River Basin anchors numerous communities from which the mine attracts qualified personnel.

The property, plant, equipment and mine development assets of NARM had a net book value of approximately $417 million at December 31, 2022. The mine’s operating equipment and facilities meet contemporary mining standards and are adequately maintained to execute the LOM plan. Routine maintenance, overhauls, and necessary capital replacements are generally included in the LOM plan to support future production.

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The table below presents NARM coal reserve estimates at December 31, 2022, along with comparative quantities at December 31, 2021. NARM did not hold any coal resources as of December 31, 2022. These reserve estimates were supported by the analyses of 4,778 total drill holes within the coal lease area. The quantity of the coal reserves is estimated on a saleable product basis and deemed 100% attributable to Peabody. In addition to quantity, the table presents selected key quality parameters on an as-shipped basis.

NARM - SUMMARY OF RESERVES (1)

(Tons in millions)

Coal Reserves (2)(3)(4) Tons %Ash %Sulfur Btu % Mine Yield(5) Tons

Year-over-year decrease (4) %

The year-over-year decrease in the quantity of coal reserves was driven by production depletion.

(3) The quality of coal reserves is estimated on an as-shipped basis.

Peabody Energy Corporation 2022 Form 10-K 50

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Shoal Creek Mine

The Shoal Creek Mine is a production-stage underground longwall metallurgical coal mine located thirty-five miles west of Birmingham, Alabama, USA. The mine is within the east-central portion of the Warrior Coal Field, which is part of the Southern Appalachian coal-producing region. The Drummond Corporation began producing coal at the mine in 1994. Peabody Energy acquired the mine from the Drummond Corporation in December 2018. The mine was idled in the fourth quarter of 2020 due to market conditions and resumed production in November 2021.

Shoal Creek Mine extracts coal from the Mary Lee and Blue Creek coal seams at depths of 1,000 to 1,300 feet. The Company has secured mineral rights through a combination of private, federal and state mineral leases and surface rights agreements which encompass a total of 31,747 acres of mineral control and 3,490 acres of surface land control. The majority of the mineral leases are private leases with negotiated royalty rates set at minimum amounts per ton or as percentages of sales realization. Shoal Creek Mine’s largest lease agreement, representing 28,517 acres of mineral control, expires in 2031 with an option to negotiate an extension. The expiration dates vary for other leases, but typically include extension provisions. As of December 31, 2022, all required licenses and permits were in place for the operations of the Shoal Creek Mine.

Coal is produced primarily using longwall systems. The mine also uses continuous miner units for longwall development and limited production. Mined coal is processed through a wash plant, conveyed to barge loadout facilities on the Black Warrior River, and transported by barge 370 miles to McDuffie Coal Terminal in Mobile Bay, Alabama, in the Gulf of Mexico, for export via ocean-going vessels. Shoal Creek Mine metallurgical coal has a well-established customer base in Europe, South America, and East Asia for steel making.

The key supporting infrastructure for Shoal Creek Mine includes road access via interstate and state highways and roads, third-party barge services and a barge loadout on the Black Warrior River, the McDuffie Coal Terminal, electrical power provided by 69kV transmission lines, and water supplied from the Black Warrior River and recycled underground water. The mine’s workforce is drawn primarily from Jasper and Tuscaloosa, Alabama and other adjacent communities.

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The property, plant, equipment and mine development assets of Shoal Creek Mine had a net book value of approximately $287 million at December 31, 2022. The mine’s operating equipment and facilities meet contemporary mining standards and are adequately maintained to execute the LOM plan. Routine maintenance, overhauls and necessary capital replacements are generally included in the LOM plan to support future production. While the mine was idled for parts of 2020 and 2021, the Company upgraded the mine’s coal handling and preparation plant and made other capital investments to improve its prospective cost structure.

The tables below present Shoal Creek Mine’s estimated coal reserves and resources at December 31, 2022, along with comparative quantities at December 31, 2021. These reserve and resource estimates were supported by the analyses of 1,178 total drill holes within the coal lease area. The quantity of the coal resources is estimated on an in situ basis as 100% attributable to Peabody. Coal resources are reported exclusive of coal reserves. The quantity of the coal reserves and resources are estimated on a saleable product basis as 100% attributable to Peabody. Coal reserves and resources are reported on selected key quality parameters on a dry basis.

SHOAL CREEK MINE - SUMMARY OF RESERVES AND RESOURCES (1)

(Tons in millions)

Coal Reserves (2)(4)(5)(6) Tons %Ash %Sulfur %VM % Mine Yield (7) Tons

Year-over-year decrease (6) %

Coal Resources (2)(3)(4)(5) Tons %Ash %Sulfur VM% Tons

The year-over-year decrease in coal reserves reflects 2022 production depletion.

(2) The quality of coal reserves and resources are estimated on a dry basis.

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Wilpinjong Mine

The Wilpinjong Mine is a production-stage surface thermal coal mine situated approximately 25 miles northeast of Mudgee in New South Wales, Australia. Peabody acquired the mine as part of its acquisition of Excel Coal Pty Ltd (Excel) in 2006. Excel began the development of Wilpinjong Mine in 2006 and it commenced production under Peabody ownership in 2007. A third-party contractor managed mining operations until 2013, when the Company converted the mine to owner-operated.

The Wilpinjong Mine extracts coal from the Moolarben and Ulan coal seams which have a combined thickness from 6 to 10 meters and a typical depth less than 60 meters in the Illawarra Coal Measures on the northwest margin of the Sydney Basin. The Company has secured three exploration licenses of 3,186 hectares and three mining licenses of 3,723 hectares through the New South Wales Minister of Planning. The typical royalty rate is 8.2% of the value of coal recovered. The mining licenses require renewal upon expiration in 2027 for 2,863 hectares and in 2039-2040 for 860 acres. The renewal application for two exploration licenses is currently pending approval and the third was granted in May 2022 for an initial term of 6 years. As of December 31, 2022, all required licenses and permits were in place for the operations of Wilpinjong.

Conventional open cut mining methods are used at the Wilpinjong Coal Mine, with multiple pits at a low strip ratio allowing for relatively rapid pit advance. Overburden is removed by a combination of cast blasting, doze, and truck and shovel methods. Haul trucks transport coal to various hoppers and pads for blending and temporary storage, as necessary, and then to a coal handling and processing plant to be crushed and washed. Coal is conveyed to a rail loadout and transported by train to either domestic customers or to the Port of Newcastle and seaborne customers for thermal power generation.

The key supporting infrastructure for Wilpinjong Mine includes road access via public roads, port service at two terminals at the Port of Newcastle, above and below rail services, electrical power from a 66kV transmission line, and water supply from captured surface runoff and deep wells. The mine’s proximity to other large coal producers in the region provides access to a significant pool of experienced mining personnel.

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The property, plant, equipment and mine development assets of Wilpinjong Mine had a net book value of approximately $342 million at December 31, 2022. The mine’s operating equipment meets contemporary mining standards and is adequately maintained to execute the LOM plan. Routine maintenance, overhauls and necessary capital replacements are generally included in the LOM plan to support future production. During 2018, the Company began an expansion project at Wilpinjong Mine that will extend the mine life from 2026 to 2030 by providing access to an additional 55 million tonnes of coal reserves. The Company capitalized approximately $62 million related to the project through December 31, 2022 and expects the total cost to reach approximately $76 million.

The tables below present Wilpinjong Mine’s estimated coal reserves and resources at December 31, 2022, along with comparative quantities at December 31, 2021. These reserve and resource estimates were supported by the analyses of 1,271 total drill holes within the coal lease area. The quantity of the coal resources is estimated on an in situ basis as 100% attributable to Peabody. Coal resources are reported exclusive of coal reserves. The quantity of the coal reserves is estimated on a saleable product basis as 100% attributable to Peabody. Coal reserves and resources are reported on selected key quality parameters on an air-dried basis.

WILPINJONG MINE - SUMMARY OF RESERVES AND RESOURCES (1)

(Tons in millions)

Coal Reserves (5)(6) Tons %Ash %Sulfur Kcal/kg % Mine Yield(7) Tons

Year-over-year decrease (12) %

Coal Resources (2)(3)(4) Tons %Ash %Sulfur Kcal/kg Tons

The year-over-year decrease in the quantity of coal reserves was driven by production depletion.

(2) The quality of coal resources is on an in situ, air-dry basis.

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Coppabella-Moorvale Joint Venture

The Company’s Coppabella Moorvale Joint Venture (CMJV) mines are located approximately 75 miles southwest of Mackay, near the township of Coppabella, in central Queensland, Australia. The CMJV includes two production-stage surface coal mines, the Coppabella Mine and the Moorvale Mine. During 2022, the Moorvale Mine substantially completed development of, and began production from, its Moorvale South pit. Peabody owns 73.3% of the joint venture and is responsible for operations management. CMJV originally was developed by Macarthur Coal Limited (Macarthur), with production commencing in 1998 at Coppabella Mine and 2002 at Moorvale Mine. Peabody acquired Macarthur in December 2011 and assumed its majority interest in CMJV.

The CMJV mines primarily extract coal from the Leichardt seam in the Rangal Coal Measures of the Bowen Basin. The seam has a thickness from 5 to 10 meters and a typical depth of less than 250 meters. The development of the Moorvale South pit made a portion of the Vermont seam economically mineable. The CMJV mines operate with a total of fourteen mining leases and one mineral development license issued by the Queensland state government, covering 13,459 hectares in total. Coal production is subject to royalties payable to the Queensland state government ranging from 7% to 40%, depending upon the realized revenue per tonne. In addition, there are special private royalty agreements established in relation to exploration efforts. The primary mining leases for the Coppabella Mine expire in 2040 and other peripheral leases expire between 2023 and 2035. The Moorvale Mine has two mining leases which expire in 2023, and a third in 2028. The Moorvale South pit has two mining leases which expire in 2030, and its relevant mineral development license expires in 2024. As of December 31, 2021, all required licenses and permits were in place for the operations of CMJV.

Conventional open cut mining methods are used at the CMJV mines. Coppabella Mine utilizes a dragline and two electric rope shovels to perform the majority of overburden removal, supplemented by diesel hydraulic excavators, which are also used to extract coal. The Moorvale Mine utilizes only diesel hydraulic excavators for overburden removal. All CMJV mines utilize cast and dozer push operations where applicable. Coal is trucked via internal haul roads for direct dumping to the hopper, or rehandled from pads to the dump hopper. Coal is crushed and washed at two processing plants, then transported by rail to the Dalrymple Bay Coal Terminal for seaborne customers. The CMJV produces a range of products including pulverized coal injection coal, coking coal and thermal coal.

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The key supporting infrastructure for CMJV includes the port service at Dalrymple Bay Coal Terminal, above and below rail services, road access via public roads, electrical power from 66kV transmission lines, and water supply from captured surface runoff and commercial pipelines. Temporary housing near the mine sites provides employees with overnight accommodations, as necessary. The mines draw personnel primarily from nearby Moranbah, Nebo and Mackay, Queensland.

The property, plant, equipment and mine development assets of CMJV had a net book value of approximately $173 million at December 31, 2021. The CMJV’s operating equipment meets contemporary mining standards and is adequately maintained to execute the mine plan. Routine maintenance, overhauls and necessary capital replacements are generally included in the LOM plan to support future production.

The tables below present estimates of the CMJV coal reserves and resources as of December 31, 2022, along with comparative quantities at December 31, 2021. These reserve and resource estimates were supported by the analyses of 4,763 total drill holes within the coal lease areas. The quantity of the coal resources is estimated on an in situ basis as 73.3% attributable to Peabody. Coal resources are reported exclusive of coal reserves. The quantity of the coal reserves is estimated on a saleable product basis as 73.3% attributable to Peabody. Coal reserves and resources are reported on selected key quality parameters on an air-dry basis.

CMJV - SUMMARY OF RESERVES AND RESOURCES (1)

(Tons in millions)

Coal Reserves (5)(6) Tons %Ash %Sulfur %VM % Mine Yield (7) Tons

Year-over-year decrease (5) %

Coal Resources (2)(3)(4) Tons %Ash %Sulfur VM% Tons

Year-over-year decrease (2) %

The decrease in reserves reflects 2022 production depletion, partially offset by the reclassification of certain mine areas to reserves; the decrease in resources reflects this reclassification.

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(2) The quality of coal resources is estimated on an in situ, air-dry basis.

— Minimum mining thickness of 0.3m for open cut

— Minimum mining thickness of 2m for underground resources

— Underground resources excluded in areas of seam dip exceeding 15 degrees

— No weathered coal included

— Intrusive sills and dykes within seams are excluded from the resources

— Heat-affected coal is included in the resources

— Other limiting factors include surface infrastructure and lease boundary

(5) The quality of coal reserves is estimated on an air-dry basis.

Internal Controls

The preparation of coal reserve and resource estimates is completed in accordance with the Company’s prescribed internal control procedures, which are designed specifically to ensure the reliability of such estimates presented herein. Annually, QPs and other employees review the estimates of mineral reserves and mineral resources, the supporting documentation, and compliance with applicable internal controls. Such controls employ management systems, standardized procedures, workflow processes, multi-functional supervision and management approval, internal and external reviews, reconciliations, and data security covering record keeping, chain of custody and data storage.

The internal controls for reserve and resource estimates also cover exploration activities, sample preparation and analysis, data verification, processing, metallurgical testing, recovery estimation, mine design and sequencing, and reserve and resource evaluations, with environmental, social and regulatory considerations. The quality assurance and control protocols over the assaying of drill hole samples are performed by reputable commercial laboratories following certification and accreditation programs established by the American Society for Testing and Materials (ASTM) or Australian National Association of Testing Authorities (NATA).

The reserve and resource estimates have inherent risks due to data accuracy, uncertainty from geological interpretation, mine plan assumptions, uncontrolled rights for mineral and surface properties, environmental challenges, uncertainty for future market supply and demand, and changes in laws and regulations. Management and QPs are aware of those risks that might directly impact the assessment of coal reserves and resources. The current coal reserves and resources are estimated based on the best information available and are subject to re-assessment when conditions change. Refer to Item 1A. “Risk Factors” for discussion of risks associated with the estimates of the Company’s reserves and resources.

Item 3. Legal Proceedings.

See Note 21. “Commitments and Contingencies” to the accompanying consolidated financial statements for a description of Peabody’s pending legal proceedings, which information is incorporated herein by reference.

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Item 4. Mine Safety Disclosures.

Peabody’s “Safety and Sustainability Management System” has been designed to set clear and consistent expectations for safety, health and environmental stewardship across the Company’s business. It aligns to the National Mining Association’s CORESafety® framework and encompasses three fundamental areas: leadership and organization, risk management and assurance. Peabody also partners with other companies and certain governmental agencies to pursue new technologies that have the potential to improve its safety performance and provide better safety protection for employees.

Peabody continually monitors its 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.

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

Peabody’s Common Stock is listed on the New York Stock Exchange, under the symbol “BTU.” As of February 17, 2023 there were 173 holders of the Company’s Common Stock, as determined by counting its record holders and the number of participants reflected in a security position listing provided to the Company by the Depository Trust Company (DTC). Because such DTC participants are brokers and other institutions holding shares of Peabody’s Common Stock on behalf of their customers, the Company does not know the actual number of unique shareholders represented by these record holders.

Dividends

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, the Company entered into a transaction support agreement with its surety bond providers which prohibits the payment of dividends through the earlier of December 31, 2025, or the maturity of the Credit Agreement (currently March 31, 2025) unless otherwise agreed to by the parties to the agreements. Additionally, restrictive covenants in its credit facility also limit the Company's ability to pay cash dividends.

Share Relinquishments

The Company routinely allows 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 its equity incentive plans. The value of Common Stock tendered by employees is determined based on the closing price of the Company’s Common Stock on the dates of the respective relinquishments.

Share Repurchase Program

On August 1, 2017, the Company announced that its Board of Directors authorized a share repurchase program to allow repurchases of up to $500 million of the then outstanding shares of its common stock and/or preferred stock (Repurchase Program), which was eventually expanded to $1.5 billion during 2018. The Repurchase Program does not have an expiration date and may be discontinued at any time. Through December 31, 2022, the Company has repurchased 41.5 million shares of its 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.

Similar to the payment of dividends as described above, the same agreements with the Company’s surety bond providers prohibit share repurchases through the earlier of December 31, 2025, or the maturity of the Credit Agreement (currently March 31, 2025) unless otherwise agreed to by the parties to the agreements. Additionally, restrictive covenants in its credit facility also limit the Company’s ability to repurchase shares. Future repurchases will be made at the Company’s discretion. The specific timing, price and size of purchases will depend upon the share price, general market and economic conditions and other considerations, including compliance with various debt agreements in effect at the time any repurchases are made.

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Issuances of Equity Securities

In June 2021, the Company announced an at-the-market equity offering program pursuant to which the Company could offer and sell up to 12.5 million shares of its Common Stock. The at-the-market equity offering program was further expanded to 32.5 million shares during 2021. The shares are offered and sold pursuant to the Company’s Registration Statement on Form S-3, which was declared effective by the Securities and Exchange Commission on April 23, 2021, as supplemented by prospectus supplements dated June 4, 2021, September 17, 2021, and December 17, 2021 relating to the offer and sale of the shares. During the year ended December 31, 2021, the Company sold approximately 24.8 million shares for net cash proceeds of $269.8 million. No sales were made under this at-the-market equity offering program during the year ended December 31, 2022, leaving approximately 7.7 million shares available for sale.

On March 7, 2022, the Company entered into an at-the-market equity offering program pursuant to which the Company could offer and sell shares of its common stock having an aggregate gross sales price of up of $225 million. The shares are offered and sold pursuant to the Company’s Registration Statement on Form S-3, which was declared effective by the Securities and Exchange Commission on April 23, 2021, as supplemented by a prospectus supplement dated March 7, 2022 relating to the offer and sale of the shares. During the year ended December 31, 2022, the Company sold approximately 10.1 million shares for net proceeds of $222.0 million, thereby concluding this at-the-market equity offering program.

Also during the year ended December 31, 2021, the Company completed multiple bilateral transactions with holders of the 2022 Notes, the 2025 Notes and the 2024 Peabody Notes in which the Company issued an aggregate 10.0 million shares of its Common Stock in exchange for $37.3 million aggregate principal amount of the 2022 Notes, $47.2 million aggregate principal amount of the 2025 Notes and $21.6 million aggregate principal amount of the 2024 Peabody Notes. No such bilateral transactions were completed during the year ended December 31, 2022. The issuance of shares of common stock in exchange for the 2022 Notes, the 2025 Notes and the 2024 Peabody Notes was made in reliance on the exemption from registration provided in Section 3(a)(9) under the Securities Act of 1933, based in part on representations of holders of the 2022 Notes, the 2025 Notes and the 2024 Peabody Notes, and on the basis that the exchange was completed with existing holders of the Company's securities and no commission or other remuneration was paid or given for soliciting the exchange.

Purchases of Equity Securities

The following table summarizes all share purchases for the three months ended December 31, 2022:

Total — — —

(1) Includes shares withheld to cover the withholding taxes upon the vesting of equity awards, which are not a part of the Repurchase Program Repurchase Program.

Stock Performance Graph

The following performance graph compares the cumulative total return on Peabody’s common stock 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 in BTU and each index was $100 at December 31, 2017. The graph also assumes that all dividends were reinvested and that the investments were held through December 31, 2022. 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 6. Reserved.

Not applicable.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

The Company’s discussion and analysis of the year ended December 31, 2022 compared to the year ended December 31, 2021 is included herein. For discussion and analysis of the year ended December 31, 2021 compared to the year ended December 31, 2020, please refer to Item 7 of Part II, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Peabody’s Annual Report on Form 10-K for the year ended December 31, 2021, which was filed with the SEC on February 18, 2022 and is incorporated by reference herein.

Non-GAAP Financial Measures

The following discussion of Peabody’s results of operations includes references to and analysis of Adjusted EBITDA and Total Reporting Segment Costs, which are financial measures 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 its segments’ operating performance and allocate resources. Total Reporting Segment Costs is also used by management as a component of a metric to measure each of its segments’ operating performance.

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Also included in the following discussion of Peabody’s results of operations are references to Revenue per Ton, Costs per Ton and Adjusted EBITDA Margin per Ton for each reporting segment. These metrics are used by management to measure each of its reporting segments’ operating performance. Management believes Costs per Ton and Adjusted EBITDA Margin per Ton best reflect controllable costs and operating results at the reporting segment level. The Company considers all measures reported on a per ton basis to be operating/statistical measures; however, the Company includes 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 its discussion of liquidity and capital resources, Peabody includes references to Free Cash Flow which is also a non-GAAP measure. Free Cash Flow is used by management as a measure of its financial performance and its ability to generate excess cash flow from its business operations.

Peabody believes non-GAAP performance measures are used by investors to measure its operating performance. 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.

Overview

In 2022, Peabody produced and sold 122.9 million and 123.7 million tons of coal, respectively, from continuing operations.

As of December 31, 2022, the Company reports its 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 the Company’s seaborne operating platform is primarily export focused with customers spread across several countries, with a portion of its thermal and metallurgical coal sold within Australia. Generally, revenue 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. The Company classifies its 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, the Company may market some of its metallurgical coal products as a thermal coal product from time to time depending on market conditions.

The Company’s 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.

The Company’s Seaborne Metallurgical Mining operations consist of mines in Queensland, Australia, one in New South Wales, Australia and one in Alabama, USA. The mines in that segment utilize both surface and underground extraction processes to mine various qualities of metallurgical coal. The metallurgical coal qualities include hard coking coal, semi-hard coking coal, semi-soft coking coal and pulverized coal injection coal.

The principal business of the Company’s thermal operating 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. The Company’s Powder River Basin Mining operations consist of its 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). The Company’s Other U.S. Thermal Mining operations reflect the aggregation of its Illinois, Indiana, New Mexico and Colorado 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, the Company’s Powder River Basin Mining operations mine sub-bituminous coal deposits and its Other U.S. Thermal Mining operations mine both bituminous and sub-bituminous coal deposits.

The Company’s Corporate and Other segment includes selling and administrative expenses, results from equity affiliates, corporate hedging activities, trading and brokerage activities, minimum charges on certain transportation-related contracts, the closure of inactive mining sites and certain commercial matters.

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Resource Management. As of December 31, 2022, Peabody controlled approximately 2.4 billion tons of proven and probable coal reserves, 2.4 billion tons of resources and approximately 360,000 acres of surface property through ownership and lease agreements. The Company has an ongoing asset optimization program whereby its property management group regularly reviews these reserves, resources and surface properties for opportunities to generate earnings and cash flow through the sale or exchange of non-strategic coal reserves, resources and surface lands. These surface lands include acres where Peabody has completed post-mining reclamation. In addition, the Company generates revenue through royalties from coal reserves and oil and gas rights leased to third parties, farm income from surface lands under third-party contracts and lease income from surface lands under contracts with renewable energy ventures.

Middlemount Mine. Peabody owns a 50% equity interest in Middlemount, which owns the Middlemount Mine in Queensland, Australia. The mine predominantly produces semi-hard coking coal and low-volatile pulverized coal injection (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, 2022 and 2021, the mine sold 1.6 million and 2.0 million tons of coal, respectively (on a 50% basis).

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 index 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, 2022 is set forth in the table below.

The seaborne pricing included in the table below is not necessarily indicative of the pricing the Company realized during the year ended December 31, 2022 due to quality differentials and a portion of its seaborne sales being executed through annual and multi-year international coal supply agreements that contain provisions requiring both parties to renegotiate pricing periodically, with spot, index and quarterly sales arrangements also utilized. The Company’s 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 the Company realized during the year ended December 31, 2022 since the Company generally sells 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 the Company’s realized pricing.

(1) Prices expressed per metric tonne.

(2) Prices expressed per short ton.

Within the global coal industry, supply and demand for its products and the supplies used for mining have been impacted by the ongoing Russian-Ukrainian conflict and the COVID-19 pandemic. Furthermore, inflationary pressures and supply chain constraints have contributed to rising costs and may continue to impact future periods. As future developments related to the Russian-Ukrainian conflict, the COVID-19 pandemic and rising inflation are unknown, the global coal industry data for the year ended December 31, 2022 presented herein may not be indicative of their ultimate impacts.

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Within the seaborne metallurgical coal market, the year ended December 31, 2022 was characterized by significant volatility as a weakened global macroeconomic environment was counteracted by tight coal supply and continued trade flow disruptions following sanctions imposed on Russian coal imports. Steel prices trended lower during the year ended December 31, 2022, causing some steelmakers to implement small-scale output cuts. The reduction in steel output is partially influencing short-term incremental metallurgical coal demand in some markets; however, it is being more than offset by transitioning demand from many steelmakers removing exposure to Russian coal by seeking additional volumes from other regions such as Australia, the U.S. and Canada. This is particularly so for PCI, where Russia typically accounts for approximately 35% of global traded volumes. In early January 2023, China partially restarted imports of Australian coal for the first time in two years, providing additional market depth and further support for prices. The Company believes energy shortages and the global inflationary environment present a risk to industrial activity in some markets, but the underlying market fundamentals remain constructive with continuing themes of supply tightness, resilient and improving demand in some markets and further economic stimulus in China and elsewhere.

Within the seaborne thermal coal market, global thermal coal prices ended the year at elevated levels, fueled by broader energy supply security concerns. These concerns have been driven by the Russian-Ukrainian conflict and the subsequent ban of Russian coal by European countries, as well as limited supply response out of Australia and Columbia due to weather and labor issues. In China, domestic coal production and renewable generation have been strong during the year ended December 31, 2022, which has lowered import demand. In India, strong growth in coal generation has supported increased import demand, despite elevated domestic coal production. Overall, global thermal coal markets remain turbulent as supply remains tight and European coal importers look to replace Russian coal.

In the United States, overall electricity demand increased more than 3% year-over-year, positively impacted by weather and economic activity. Through the year ended December 31, 2022, electricity generation from thermal coal has declined year-over-year due to coal conservation by utilities, transportation issues impacting coal deliveries and stronger renewable generation. Coal’s share of electricity generation has declined to approximately 19% for the year ended December 31, 2022, while wind and solar’s combined generation share has increased to 15%. Coal inventories have continued to decline since December 2021, with a decline of approximately 6% or 5 million tons. During the year ended December 31, 2022, utility consumption of PRB coal declined approximately 5% compared to the prior year period.

Financing Transactions

During the first quarter of 2022, Peabody issued convertible senior unsecured notes and used the proceeds of the offering to retire nearer term higher cost senior secured debt. This both lowered the Company’s borrowing rates and extended debt maturities to 2028. Throughout 2022, Peabody continued to reduce its outstanding debt, and at December 31, 2022, all senior secured debt had been retired.

High demand and tight supply for coal globally has resulted in a substantial rise in seaborne thermal coal prices during 2022, which has been amplified by the Russian-Ukrainian conflict, resulting in unprecedented upward volatility in Newcastle coal pricing since late February 2022. As a result, Peabody posted additional cash margin of $125.4 million during the year ended December 31, 2022 to satisfy the margin requirements for its derivative contracts.

Refer to the “Liquidity and Capital Resources” section contained within this Item 7 for a further discussion of these financing and liquidity transactions.

North Goonyella Redevelopment

During the third quarter of 2022, the Company initiated the redevelopment of its North Goonyella Mine, a premium hard-coking coal longwall operation in Australia with over 70 million tons of coal reserves. The project will utilize substantial existing infrastructure and equipment at the mine, including a new 300-meter longwall system, a coal handling preparation plant, a dedicated rail loop for transport to the Dalrymple Bay Coal Terminal and an accommodation village with housing and service amenities for more than 400 workers. North Goonyella is anticipated to increase the Company’s production in its Seaborne Metallurgical Mining segment.

The Company’s board of directors has approved redevelopment expenditures of $120 million for 2023, which include ventilation, equipment, conveyance and infrastructure updates in anticipation of reaching development coal, subject to regulatory approvals, in the first quarter of 2024. Cash flow from operations is expected to fund all redevelopment costs as the Company continues to strengthen its balance sheet. Future decisions about the redevelopment of North Goonyella may be impacted by Queensland’s increased royalty tiers. Development costs in addition to the current approved amount are estimated to be $240 million, with longwall operations expected to commence in 2026.

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Other

In March 2022, the Company entered into a joint venture with unrelated partners to form R3 Renewables LLC (R3). R3 was formed with the intent of developing various sites, including certain reclaimed mining land held by the Company in the U.S., for utility-scale photovoltaic solar generation and battery storage. During 2022, R3 has advanced efforts with potential customers, finalized its management team and commenced site evaluations with project developer Treaty Oak Clean Energy, LLC. The Company’s interest in R3 is accounted for as an equity method investment. The Company contributed $10.9 million to R3 and recorded an equity loss of $3.9 million from its operations during the year ended December 31, 2022.

In March 2022, Peabody Investments Corp., a wholly owned subsidiary of the Company, entered into a commitment agreement relating to one of its qualified pension plans (the Plan) with an insurer. Under the commitment agreement, the Plan purchased a buy-in group annuity contract for approximately $500 million and the insurer will reimburse the Plan for benefit payments to be made to the Plan’s participants. Under the terms of this transaction, the Plan continues to administer and pay the retirement benefits of Plan participants and is reimbursed by the insurer for the payment of all benefits covered by the group annuity contract. In May 2022, the board of directors of Peabody Investments Corp. approved the termination of the Plan effective July 31, 2022. Refer to Note 14. “Pension and Savings Plans” to the accompanying consolidated financial statements for a further discussion of this transaction.

Results of Operations

Year Ended December 31, 2022 Compared to Year Ended December 31, 2021

The increase in income from continuing operations, net of income taxes for the year ended December 31, 2022 compared to the same period in 2021 ($970.0 million) was primarily driven by higher revenue ($1,663.6 million) due to higher realized prices and a 20% increase in metallurgical sales volumes; improved results from equity affiliates ($49.1 million); and lower interest expense ($43.1 million). These favorable variances were partially offset by higher operating costs and expenses ($737.7 million), which reflect increased sales price sensitive costs, the impacts of challenging weather conditions and inflationary pressures for commodities, materials, services, repairs and labor; and net losses on early debt extinguishments in the current year ($91.1 million).

Adjusted EBITDA for the year ended December 31, 2022 reflected a 101% year-over-year increase of $928.0 million.

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 6.6 5.5 1.1 20.0 %

Total tons sold from operating segments 123.2 128.1 (4.9) (3.8) %

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Supplemental Financial Data

The following table presents supplemental financial data by operating segment:

Year Ended December 31, Increase (Decrease)

Revenue 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; amortization of take-or-pay contract-based intangibles; and certain other costs related to post-mining activities.

Revenue

The following table presents revenue by reporting segment:

Increase

Year Ended December 31, to Revenue

(Dollars in millions)

Seaborne Thermal Mining. The increase in segment revenue during the year ended December 31, 2022 compared to the prior year was due to favorable realized prices ($540.4 million), partially offset by unfavorable volumes ($128.8 million) which were impacted by wet weather in the current year and mine plan considerations which included a longwall move at the Wambo Underground Mine in the first half of 2022.

Seaborne Metallurgical Mining. Segment revenue increased during the year ended December 31, 2022 compared to the prior year due to favorable realized prices at the Australian operations ($583.1 million), the resumption of sales at the Shoal Creek Mine ($236.6 million) and favorable volume and mix variances at the Australian operations ($69.5 million). Sales volumes increased by 20% from the prior year.

Powder River Basin Mining. Segment revenue increased during the year ended December 31, 2022 compared to the prior year due to favorable realized prices ($168.5 million), offset by unfavorable volumes ($74.2 million) resulting from rail performance issues.

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Other U.S. Thermal Mining. The increase in segment revenue during the year ended December 31, 2022 compared to the prior year was due to favorable realized prices ($209.2 million) and favorable volumes ($53.9 million).

Corporate and Other. Segment revenue increased during the year ended December 31, 2022 compared to the prior year due to lower net unrealized mark-to-market losses on derivative contracts related to forecasted coal sales ($79.3 million), offset by lower results from trading activities ($74.5 million) due to net realized losses on derivative contracts related to forecasted coal sales exceeding the higher margins recognized on the physical sale of coal.

Adjusted EBITDA

The following table presents Adjusted EBITDA for each of the Company’s reporting segments:

Increase (Decrease) 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 increased during the year ended December 31, 2022 compared to the same period in the prior year as a result of higher realized prices net of sales sensitive costs ($495.5 million) and favorable foreign currency impacts ($25.2 million). The increases were offset by unfavorable operational costs ($119.8 million) resulting from the impacts of wet weather, COVID-19-related staffing shortages, the longwall move at the Wambo Underground Mine in the first half of 2022 and inflationary pressures on supplies and outside services; lower volumes ($64.7 million); higher port and demurrage costs ($21.7 million) and higher commodity pricing ($18.6 million).

Seaborne Metallurgical Mining. Segment Adjusted EBITDA increased during the year ended December 31, 2022 compared to the same period in the prior year due to higher realized prices net of sales sensitive costs at the Australian operations ($466.9 million), favorable volumes from the resumption of sales at the Shoal Creek Mine ($111.6 million) and favorable foreign currency impacts ($36.3 million).

Powder River Basin Mining. Segment Adjusted EBITDA decreased during the year ended December 31, 2022 compared to the same period in the prior year as a result of increased overburden removal costs as the workforce focused on preparatory efforts in light of rail performance issues ($63.3 million); higher costs for materials, services, repairs and labor ($55.3 million) due in part to increased repairs for an aging equipment fleet and inflationary pressures on materials and services; the unfavorable impacts of higher commodity pricing ($53.9 million); and lower volumes ($19.9 million) resulting from rail performance issues. These decreases were offset by higher realized prices net of sales sensitive costs ($146.7 million).

Other U.S. Thermal Mining. Segment Adjusted EBITDA increased during the year ended December 31, 2022 compared to the same period in the prior year due to higher realized prices net of sales sensitive costs ($210.4 million) and favorable volumes ($19.2 million). These increases were offset by higher costs for materials, services, repairs and labor ($104.8 million) due in part to increased equipment repairs and headcount resulting from increasing volume demands and inflationary pressures on materials and services; and the unfavorable impacts of higher commodity pricing ($44.2 million).

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Corporate and Other Adjusted EBITDA. The following table presents a summary of the components of Corporate and Other Adjusted EBITDA:

Increase (Decrease)

Year Ended December 31, to Income

(Dollars in millions)

Selling and administrative expenses (88.8) (84.9) (3.9) (4.6) %

(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 $62.7 million and $42.0 million during the years ended December 31, 2022 and 2021, respectively.

(2)Includes gains (losses) on certain surplus coal reserve, resource and surface land sales and property management costs and revenue.

(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 other commercial activities.

Corporate and Other Adjusted EBITDA benefited during the year ended December 31, 2022 compared to the same period in the prior year from favorable variances in Middlemount’s results due to the impact of higher sales pricing ($84.6 million) and gains on various land sales in both the U.S. and Australia ($20.0 million). This benefit was offset by unfavorable trading results ($61.6 million) and a gain recognized in the prior year on the sale of the Company’s Millennium Mine ($26.1 million) as discussed in Note 17. “Other Events.”

Income From Continuing Operations, Net of Income Taxes

The following table presents income from continuing operations, net of income taxes:

Increase (Decrease) to Income

Year Ended December 31,

(Dollars in millions)

Depreciation, depletion and amortization (317.6) (308.7) (8.9) (2.9) %

Asset retirement obligation expenses (49.4) (44.7) (4.7) (10.5) %

Asset impairment (11.2) — (11.2) n.m.

Net (loss) gain on early debt extinguishment (57.9) 33.2 (91.1) (274.4) %

Unrealized losses on foreign currency option contracts (2.3) (7.5) 5.2 69.3 %

Take-or-pay contract-based intangible recognition 2.8 4.3 (1.5) (34.9) %

(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.

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Depreciation, Depletion and Amortization. The following table presents a summary of depreciation, depletion and amortization expense by reporting segment:

(Decrease) Increase

Year Ended December 31, to Income

(Dollars in millions)

Powder River Basin Mining (42.5) (41.5) (1.0) (2.4) %

Additionally, the following table presents a summary of the Company’s weighted-average depletion rate per ton for active mines in each of its operating segments:

Year Ended December 31,

Seaborne Thermal Mining $ 2.61 $ 2.19

Seaborne Metallurgical Mining 2.55 1.18

Powder River Basin Mining 0.32 0.25

Other U.S. Thermal Mining 1.23 1.15

The increase in the weighted-average depletion rate per ton for the Seaborne Thermal Mining segment during the year ended December 31, 2022 compared to the same period in the prior year reflects the impact of volume and mix variances across the segment. The increase in the Seaborne Metallurgical Mining segment during the year ended December 31, 2022 compared to the same period in the prior year reflects the resumption of sales at the Shoal Creek Mine.

Asset Impairment. The Company recognized $11.2 million in aggregate asset impairment charges during the year ended December 31, 2022 related to the sale of certain land interests and an investment in equity securities. 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.

Changes in Deferred Tax Asset Valuation Allowance and Reserves and Amortization of Basis Difference Related to Equity Affiliates. During the year ended December 31, 2021, the Company released a valuation allowance of approximately $33 million previously recorded on Middlemount’s deferred tax assets as a result of taxable income generated during 2021. As of December 31, 2021, no valuation allowance remained related to Middlemount’s deferred tax assets so there is no release reflected in 2022. The current year income activity relates only to the amortization of basis differences which is comparable to prior periods. Refer to Note 5. “Equity Method Investments” to the accompanying consolidated financial statements for further information regarding these changes, which information is incorporated herein by reference.

Interest Expense. The decrease in interest expense during the year ended December 31, 2022 compared to the prior year primarily reflects debt retirements completed by the Company during 2022 and 2021 and prior year fees related to a series of refinancing transactions completed by the Company as further described in Note 10. “Long-term Debt” to the accompanying consolidated financial statements.

Net (Loss) Gain on Early Debt Extinguishment. The net loss (gain) on early debt extinguishment was primarily related to the redemption of existing notes during the years ended December 31, 2022 and 2021, as further discussed in Note 10. “Long-term Debt” to the accompanying consolidated financial statements.

Interest Income. The increase in interest income during the year ended December 31, 2022 compared to the prior year was primarily due to higher cash balances and interest rates in the current year.

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Net Mark-to-Market Adjustment on Actuarially Determined Liabilities. The gain recorded during the year ended December 31, 2022 was driven by increases to the discount rates for actuarially determined liabilities ($190.1 million) and the favorable impacts of changes for the postretirement benefit plans related to updated claims experience ($28.6 million). These increases were offset by mark-to-market losses on pension and postretirement benefit plan assets ($162.1 million); the unfavorable impact of the premium paid for the purchase of a buy-in group annuity contract for a qualified pension plan ($17.6 million) and the unfavorable impacts of medical trend updates for the postretirement benefit plans ($15.7 million).

The gain recorded during the year ended December 31, 2021 was driven by increases to the discount rates for actuarially determined liabilities ($37.6 million); the favorable impacts of changes for the postretirement benefit plans related to updated claims experience ($22.0 million) and a mortality update ($16.6 million); and the favorable impact of an update to the Company’s census data for actuarially determined liabilities ($10.3 million). These increases were offset by mark-to-market losses on pension and postretirement benefit plan assets ($43.1 million).

Unrealized Losses on Derivative Contracts Related to Forecasted Sales. Unrealized losses primarily relate to mark-to-market activity on derivative contracts related to forecasted coal sales. For additional information, refer to Note 6. “Derivatives and Fair Value Measurements” to the accompanying consolidated financial statements.