UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
| ☑ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |||||||||||||||||||
| For the Fiscal Year Ended | December 31, | |||||||||||||||||||
or
| ☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |||||||||||||
Commission File Number 1-16463
PEABODY ENERGY CORPORATIONCORPORATION
(Exact name of registrant as specified in its charter)
| Delaware | 13-4004153 | |||||||
| (State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | |||||||
| 701 Market Street, | St. Louis, | Missouri | 63101-1826 | |||||||||||||||||
| (Address of principal executive offices) | (Zip Code) | |||||||||||||||||||
(Registrant’s telephone number, including area code)
Securities Registered Pursuant to Section 12(b) of the Act:
| Title of Each Class | Trading Symbol(s) | Name of Each Exchange on Which Registered | ||||||
| Common Stock, par value $0.01 per share | BTU | New York Stock Exchange | ||||||
Securities Registered Pursuant to Section 12(g) of the Act:
None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☑
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☑
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☑ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☑ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer ☑ Accelerated filer ☐
Non-accelerated filer ☐ Smaller reporting company ☐
Emerging growth company ☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☑
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☑
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐
Aggregate market value of the voting stockand non-voting common equity held by non-affiliates (stockholders who are not directors or executive officers) of the Registrant, calculated using the closing price on June 30, 2019:2022: Common Stock, par value $0.01 per share, $1.9$2.5 billion.
Number of shares outstanding of each of the Registrant’s classes of Common Stock, as of February 18, 2020:17, 2023: Common Stock, par value $0.01 per share, 97,108,831144,236,926 shares outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Company’s Proxy Statement to be filed with the Securities and Exchange Commission in connection with the Company’s 20202023 Annual Meeting of Shareholders (the Company’s 20202023 Proxy Statement) are incorporated by reference into Part III hereof. Other documents incorporated by reference in this report are listed in the Exhibit Index of this Form 10-K.
CAUTIONARY NOTICE REGARDING FORWARD-LOOKING STATEMENTS
This report includes statements of ourthe Company’s expectations, intentions, plans and beliefs that constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the Securities Act), and Section 21E of the Securities Exchange Act of 1934, as amended (the Exchange Act), and are intended to come within the safe harbor protection provided by those sections. These statements relate to future events or ourthe Company’s future financial performance, including, without limitation, the section captioned “Outlook” in Management’s Discussion and Analysis of Financial Condition and Results of Operations. We useperformance. The Company uses words such as “anticipate,” “believe,” “expect,” “may,” “forecast,” “project,” “should,” “estimate,” “plan,” “outlook,” “target,” “likely,” “will,” “to be” or other similar words to identify forward-looking statements.
Without limiting the foregoing, all statements relating to ourthe Company’s future operating results, anticipated capital expenditures, future cash flows and borrowings, and sources of funding are forward-looking statements and speak only as of the date of this report. These forward-looking statements are based on numerous assumptions that we believethe Company believes are reasonable, but are subject to a wide range of uncertainties and business risks, and actual results may differ materially from those discussed in these statements. These factors include but are not limited to those described in Part I, Item 1A. “Risk Factors.” Such factors are difficult to accurately predict and may be beyond ourthe Company’s control. Factors that could affect our results or an investment in our securities include, but are not limited to:
When considering these forward-looking statements, you should keep in mind the cautionary statements in this document and in ourthe Company’s other Securities and Exchange Commission (SEC) filings. These forward-looking statements speak only as of the date on which such statements were made, and we undertakethe Company undertakes no obligation to update these statements except as required by federal securities laws.
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TABLE OF CONTENTS
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| Note: | The words | ||||
| When used in this filing, the term “ton” refers to short or net tons, equal to 2,000 pounds (907.18 kilograms), while “tonne” refers to metric tons, equal to 2,204.62 pounds (1,000 kilograms). | |||||
PART I
Item 1. Business.
Overview
In addition to ourits mining operations, we marketthe Company markets and brokerbrokers coal from other coal producers, both as principal and agent, and tradetrades coal and freight-related contracts, through trading and, business officesduring 2022, partnered in a joint venture with the intent of developing various sites, including certain reclaimed mining land held by the Company in the U.S., Australia, Chinafor utility-scale photovoltaic solar generation and the United Kingdom.battery storage.
Segment and Geographic Information
As of December 31, 2019, we report our results of operations primarily through the following reportable segments: Seaborne Thermal Mining, Seaborne Metallurgical Mining, Powder River Basin Mining, Midwestern U.S. Mining, Western U.S. Mining and Corporate and Other.
Mining Locations
The maps that follow display ourPeabody’s active mine locations as of December 31, 2019.2022. Also shown are the primary ports that we usethe Company uses for ourits coal exports and ourthe Company’s corporate headquarters in St. Louis, Missouri.
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U.S. Locations
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Australian Locations
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The table below summarizes information regarding the operating characteristics of each of ourthe Company’s mines that were active in 2019 in the U.S. and Australia. The mines are listed within their respective miningreporting segment in descending order, as determined by tons soldproduced in 2019.2022.
| Production | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Segment/Mining Complex | Location | Mine Type | Mining Method | Coal Type | Primary Transport Method | Processing Plants | Year Ended December 31, | |||||||||||||||||||||||||||||||||||||||||||||||||
| 2022 | 2021 | 2020 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Seaborne Thermal Mining | (Tons in millions) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Wilpinjong | New South Wales | S | D, T/S | T | R, EV | Yes | 12.1 | 13.2 | 14.2 | |||||||||||||||||||||||||||||||||||||||||||||||
Wambo Open-Cut (1) | New South Wales | S | T/S | T, C | R, EV | Yes | 2.0 | 2.4 | 4.0 | |||||||||||||||||||||||||||||||||||||||||||||||
Wambo Underground (2) | New South Wales | U | LW | T, C | R, EV | Yes | 1.1 | 1.4 | 1.5 | |||||||||||||||||||||||||||||||||||||||||||||||
| Seaborne Metallurgical Mining | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Coppabella (3) | Queensland | S | DL, D, T/S | P | R, EV | Yes | 2.4 | 2.1 | 2.2 | |||||||||||||||||||||||||||||||||||||||||||||||
Metropolitan (4) | New South Wales | U | LW | C, P, T | R, EV | Yes | 1.8 | 1.0 | 1.0 | |||||||||||||||||||||||||||||||||||||||||||||||
Moorvale (3) | Queensland | S | D, T/S | C, P, T | R, EV | Yes | 1.5 | 1.3 | 1.2 | |||||||||||||||||||||||||||||||||||||||||||||||
Shoal Creek (5) | Alabama | U | LW | C | B, EV | Yes | 0.8 | 0.1 | 0.6 | |||||||||||||||||||||||||||||||||||||||||||||||
Millennium (6) | Queensland | S | HW | C, P | R, EV | No | — | — | 0.1 | |||||||||||||||||||||||||||||||||||||||||||||||
Middlemount (7) | Queensland | S | D, T/S | C, P | R, EV | Yes | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||||
| Powder River Basin Mining | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| North Antelope Rochelle | Wyoming | S | DL, D, T/S | T | R | No | 60.4 | 62.8 | 66.1 | |||||||||||||||||||||||||||||||||||||||||||||||
| Caballo | Wyoming | S | D, T/S | T | R | No | 12.1 | 13.9 | 11.6 | |||||||||||||||||||||||||||||||||||||||||||||||
| Rawhide | Wyoming | S | D, T/S | T | R | No | 10.3 | 11.6 | 9.5 | |||||||||||||||||||||||||||||||||||||||||||||||
| Other U.S. Thermal Mining | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Bear Run | Indiana | S | DL, D, T/S | T | Tr, R, EV | Yes | 6.7 | 6.0 | 5.2 | |||||||||||||||||||||||||||||||||||||||||||||||
| El Segundo/Lee Ranch | New Mexico | S | DL, D, T/S | T | R | No | 3.7 | 3.7 | 4.6 | |||||||||||||||||||||||||||||||||||||||||||||||
| Gateway North | Illinois | U | CM | T | Tr, R, R/B, T/B, EV | Yes | 2.4 | 1.8 | 1.8 | |||||||||||||||||||||||||||||||||||||||||||||||
| Wild Boar | Indiana | S | HW, DL, D, T/S | T | Tr, R, R/B, T/B | Yes | 2.3 | 2.4 | 2.0 | |||||||||||||||||||||||||||||||||||||||||||||||
| Francisco Underground | Indiana | U | CM | T | R | Yes | 1.8 | 1.5 | 1.6 | |||||||||||||||||||||||||||||||||||||||||||||||
| Twentymile | Colorado | U | LW | T | R, Tr, EV | Yes | 1.5 | 1.7 | 1.2 | |||||||||||||||||||||||||||||||||||||||||||||||
Somerville Central (6) | Indiana | S | DL, D, T/S | T | R, R/B, T/B, T/R | No | — | — | 0.4 | |||||||||||||||||||||||||||||||||||||||||||||||
| Surface Mine | B | Barge | ||||||||||||
| Highwall Miner | R/B | Rail to Barge | ||||||||||||
| DL | Dragline | T/B | Truck to Barge | |||||||||||
| D | Dozer/Casting | T/R | Truck to Rail | |||||||||||
| T/S | Truck and Shovel | EV | Export Vessel | |||||||||||
| LW | Longwall | T | Thermal/Steam | |||||||||||
| CM | Continuous Miner | C | Coking | |||||||||||
| R | Rail | P | Pulverized Coal Injection | |||||||||||
(1)In December 2020, the United Wambo Joint Venture, an unincorporated joint venture between Peabody and Glencore plc, began joint production. The tons shown reflect Peabody’s proportionate share throughout the years. The Company’s 50% joint venture interest is subject to an outside non-controlling ownership interest. (2)Majority-owned mine in which there is an outside non-controlling ownership interest. (3)Peabody owns a 73.3% undivided interest in an unincorporated joint venture that owns the Coppabella and Moorvale mines. The tons shown reflect its share. (4)The mine was idled in the fourth quarter of 2020. The mine restarted production in the second quarter of 2021. (5)The mine was idled in the fourth quarter of 2020. The mine restarted production in November 2021. (6)The mine ceased production during 2020. (7)Peabody owns a 50% equity interest in Middlemount, which owns the Middlemount Mine. Because Middlemount is accounted for as an unconsolidated equity affiliate, the table above excludes tons produced from that mine, which totaled 1.4 million, 2.0 million and 1.6 million tons, respectively (on a 50% basis). |
Refer to the “Summary of Coal ProductionReserves and Sulfur Content of Assigned Reserves” tableResources tables within Part I, Item 2. “Properties,” which is incorporated by reference herein, for additional information regarding coal reserves and resources, and product characteristics and production volume associated with each mine.
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Coal Supply Agreements
Customers. OurPeabody’s coal supply agreements are primarily with electricity generators, industrial facilities and steel manufacturers. Most of ourthe Company’s sales from ourits mining operations are made under long-term coal supply agreements (those with initial terms of one year or longer and which often include price reopener and/or extension provisions). A smaller portion of ourthe Company’s sales from ourits mining operations are made under contracts with terms of less than one year, including sales made on a spot basis. Sales under long-term coal supply agreements comprised approximately 88%85%, 87%84% and 83%89% of ourthe Company’s worldwide sales from ourits mining operations (by volume) for the years ended December 31, 2019, 20182022, 2021 and 2017,2020, respectively. A recent trend has been for our customers under long-term coal supply agreements to seek contracts of shorter duration.
For the year ended December 31, 2019, we2022, Peabody derived 33%28% of our revenuesits revenue from coal supply agreements from ourits five largest customers. Those five customers were supplied primarily from 4316 coal supply agreements (excluding trading and brokerage transactions) expiring at various times from 20202023 to 2025. ThePeabody’s largest customer contributing the greatest amountin 2022 contributed revenue of annual revenue in 2019 was approximately $477$358 million, or approximately 11%7% of our 2019Peabody’s total revenuesrevenue from coal supply agreements, and has contracts expiring at various times from 20212023 to 2023.2024.
Backlog. OurPeabody’s sales backlog, which includes coal supply agreements subject to price reopener and/or extension provisions, was approximately 327314 million and 401283 million tons of coal as of January 1, 20202023 and 2019,2022, respectively. Contracts in backlog have remaining terms ranging from one to seventen years and represent approximately twothree years of production based on our 2019the Company’s 2022 production volume of 164.7122.9 million tons. Approximately 59%62% of ourits backlog is expected to be filled beyond 2020.2023.
Seaborne Mining Operations. RevenuesRevenue from ourPeabody’s Seaborne Thermal Mining and Seaborne Metallurgical Mining segments represented approximately 45%59%, 48%50% and 46%42% of ourthe Company’s total revenuesrevenue from coal supply agreements for the years ended December 31, 2019, 20182022, 2021 and 2017,2020, respectively, during which periods the coal mining activities of those segments contributed respective amounts of 17%18%, 16%18% and 16%19% of ourthe Company’s sales volumes from mining operations. Our productionProduction from these segments is primarily sold into the seaborne thermal and metallurgical markets, with a majority of those sales executed through annual and multi-year international coal supply agreements that contain provisions requiring both parties to renegotiate pricing periodically.periodically, with spot, index and quarterly sales arrangements also utilized. Industry commercial practice, and ourPeabody’s typical practice, is to negotiate pricing for seaborne thermal coal contracts on an annual, spot or index basis and seaborne metallurgical coal contracts on a quarterly, spot or index basis. For ourits seaborne mining operations, the portion of sales volume under contracts with a duration of less than one year represented 29%41% in 2019.2022.
U.S. Thermal Mining Operations. RevenuesRevenue from ourPeabody’s Powder River Basin Mining Westernand Other U.S. Mining and Midwestern U.S.Thermal Mining segments, in aggregate, represented approximately 55%41%, 52%50% and 53%58% of our revenuesthe Company’s revenue from coal supply agreements for the years ended December 31, 2019, 20182022, 2021 and 2017,2020, respectively, during which periods the coal mining activities of those segments contributed respective aggregate amounts of approximately 83%82%, 84%82% and 84%81% of ourthe Company’s sales volumes from mining operations. We expectThe Company expects to continue selling a significant portion of coal production from ourits U.S. thermal miningoperating segments under existing long-term supply agreements, andagreements. Certain customers of those segments generally favorutilize long-term sales agreements in recognition of the importance of reliability, service and predictable coal prices to their operations. The terms of coal supply agreements result from competitive bidding and extensive negotiations with customers. Consequently, the terms of those agreements 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. OurPeabody’s approach is to selectively renew, or enter into new, long-term supply agreements when weit can do so at prices and terms and conditions we believeit believes are favorable. Over the last few years, Peabody’s customers have shifted to long-term supply agreements with shorter durations, driven by the reduced utilization of plants and plant retirements, fluidity of natural gas pricing and the increased use of renewable energy sources.
Transportation
Methods of Distribution. Coal consumed in the U.S. is usually sold at the mine with transportation costs borne by the purchaser. OurPeabody’s U.S. mine sites are typically adjacent to a rail loop; however, in limited circumstances coal may be trucked to a barge site or directly to customers. Title predominately passes to the purchaser at the rail or barge, as applicable. OurPeabody’s U.S. and Australian export coal is usually sold at the loading port, with purchasers paying ocean freight. In each case, wethe Company usually paypays transportation costs from the mine to the port, including any demurrage costs (fees paid to third-party shipping companies for loading time that exceeded the stipulated time).
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The Company believes it has good relationships with U.S. and Australian rail carriers and port and barge companies due, in part, to ourits modern coal-loading facilities and the experience of ourits transportation coordinators. During the year ended December 31, 2022, rail service constraints due, in part, to labor shortages and weather conditions experienced by Peabody’s rail service providers, have negatively impacted U.S. thermal shipment volumes. Refer to the table in the foregoing “Mining Locations” section for a summary of transportation methods by mine.
Export Facilities. Our seaborne mining operations sold approximately 71%, 75% and 73% of its tons into the seaborne coal markets for the years ended December 31, 2019, 2018 and 2017, respectively. We havePeabody has generally secured ourits ability to transport coal in Australia through rail and port contracts and access to five east coast coalcoal export terminals that are primarily funded through take-or-pay arrangements (refer to the “Liquidity and Capital Resources” section in Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for additional information on ourits take-or-pay obligations). In Queensland, seaborne thermal and metallurgical coal from ourthe Company’s mines is exported through the Dalrymple Bay Coal Terminal, in addition to the Abbot Point Coal Terminal used by ourits joint venture Middlemount Mine. In New South Wales, ourthe Company’s primary ports for exporting thermal and metallurgical coal are at Port Kembla and Newcastle, which includes both the Port Waratah Coal Services terminal and the terminal operated by Newcastle Coal Infrastructure Group. We havePeabody has secured ourits ability to transport coal from ourits Shoal Creek Mine under barge and port contracts; the primary port is the McDuffie Terminal in Mobile, Alabama, which we utilizethe Company utilizes without a take-or-pay arrangement.
Suppliers
Mining Supplies and Equipment. The principal goods we purchasePeabody purchases in support of ourits mining activities are mining equipment and replacement parts, diesel fuel, ammonium-nitrate and emulsion-based explosives, off-the-road tires, steel-related products (including roof control materials), lubricants and electricity. We havePeabody has many well-established, strategic relationships with ourits key suppliers of goods and dodoes not believe that we areit is overly dependent on any of ourits individual suppliers.
In situations where we havePeabody has elected to concentrate a large portion of ourits purchases with one supplier, it has been to take advantage of cost savings from larger volumes of purchases, benefit from long-term pricing for parts and ensure security of supply and/or allow for equipment fleet standardization.supply. Supplier concentration related to ourthe Company’s mining equipment also allows usit to benefit from fleet standardization, which in turn improves asset utilization by facilitating the development of common maintenance practices across ourits global platform, enhancing ourits flexibility to move equipment between mines and reduce working capital through inventory optimization.
Surface and underground mining equipment demand and lead times for parts and components have remained steadyincreased in recent periods. WePeabody consistently use ouruses its global leverage with major suppliers and comprehensive planning processes to ensure security of supply to meet the requirements of ourits active mines.
Services. WePeabody also purchasepurchases services at ourits mine sites, including services related to maintenance for mining equipment, construction, temporary labor, use of explosives and various other requirements. We doPeabody does not believe that we haveit has undue operational or financial risk associated with ourits dependence on any individual service providers.
Throughout 2022, inflationary pressures and supply chain constraints have contributed to rising costs for mining equipment, supplies and services. This trend may continue to impact future periods.
Competition
Demand for coal and the prices that wethe Company will be able to obtain for ourits coal are highly competitive and influenced by factors beyond ourthe Company’s control, including but not limited to global economic conditions; the demand for electricity and steel; the cost of alternative fuels, including wind, solar, oil, hydro, nuclear, natural gas and biomass;sources; the impact of weather on heating and cooling demand; the capacity and cost of transportation; geopolitical risks; and taxes and environmental regulations imposed by the U.S. and foreign governments.
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Thermal Coal
Coal. Demand for ourPeabody’s thermal coal products is impacted by economic conditions,conditions; demand for electricity, including the impact ofwhich is impacted by energy efficient products,products; and the cost of electricity generation from coal and alternative forms of generation. OurRegulatory policies and environmental, social and governance considerations can also have an impact on generation choices and coal consumption. The Company’s products compete with producers of other forms of electricity generation, including natural gas, oil, nuclear, hydro, wind, solar and biomass, that provide an alternative to coal use. The use and price of thermal coal is heavily influenced by the availability and relative cost of alternative fuelsfuel sources and the generation of electricity utilizing alternative fuels, with customers focused on securing the lowest cost fuel supply in order to coordinate the most efficient utilization of generating resources in the economic dispatch of the power grid at the most competitive price. Regulatory policies and environmental, social and governance considerations can also have an impact on generation choices and coal consumption.
In the U.S., natural gas is highly competitive (along with other alternative fuel sources) with thermal coal for electricity generation. The competitiveness of natural gas has been strengthened by accelerated growth in domestic natural gas production and new natural gas combined cycle generation capacity as well as comparatively low natural gas prices (versus historic levels).capacity. The Henry Hub Natural Gas Prompt Price averaged $2.53$6.54 per mmBtu in 2019,2022, versus $3.07$3.72 and $3.02$2.13 per mmBtu in 20182021 and 2017,2020, respectively. The growth in domestic natural gas production and logistical constraints has led to discounts for regional gas prices versus the Henry Hub price, further driving lower natural gas price trends. In addition, the competitiveness of other alternative fuel sources for electricity generation with coal has been strengthened by the growth of low-cost and government subsidized generation fueled by other alternative fuel sources.renewable energy generation. These pressures, coupled with increasing regulatory burdens, have contributed to a significant number of coal plant retirements. During 2019,2022, approximately 1412 gigawatts of U.S. coal power capacity was retired, and since 2010, U.S. coal power capacity has fallen by more than a quarter.approximately thirty-six percent.
Internationally, thermal coal also competes with alternative forms of electricity generation. The competitiveness and availability of natural gas, liquefied natural gas, oil, nuclear, hydro, wind, solar and biomass varies by country and region. Seaborne thermal coal consumption is also impacted by the competitiveness of delivered seaborne thermal coal supply from key exporting countries such as Indonesia, Australia, Russia, Colombia, the U.S., Russia and South Africa, among others. 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, among others. China’s unofficial ban on Australian coal in recent years continued until January 2023 and impeded traditional trade flows. Global thermal coal markets have been turbulent during 2022, due in part to the Russian-Ukrainian conflict and the subsequent ban of Russian coal by European countries.
In addition to ourits alternative fuel source competitors, ourPeabody’s principal U.S. direct coal supply competitors (listed alphabetically) are other large coal producers, including Alliance Resource Partners,Partners; American Consolidated Natural Resources, Inc.; Arch Resources, Inc.; CONSOL Energy,Energy; Eagle Specialty Materials LLC, Murray Energy CorporationLLC; Foresight Energy; Hallador Energy; Kiewit; and Navajo Transitional Energy Company LLC, among others. Major international direct coal supply competitors (listed alphabetically) include Adaro Energy; Anglo American plc, BHP,plc; BHP; Bumi Resources; China Shenhua Energy,Energy; Coal India Limited,Limited; Drummond Company, Glencore, PT Adaro Energy Tbk, SUEK,Company; Glencore; South32; SUEK; Whitehaven Coal LimitedLimited; and Yancoal Australia Ltd, among others.
Metallurgical Coal
Coal. Demand for ourPeabody’s metallurgical coal products is impacted by economic conditions,conditions; government policies,policies; demand for steelsteel; and competing technologies used to make steel, some of which do not use coal as a manufacturing input. We competeinput, such as electric arc furnaces. The Company competes on the basis of 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, and the competitiveness of seaborne metallurgical coal supply including from leading metallurgical coal exporting countries of Australia, the U.S., Russia, Canada, Mongolia and Mozambique, among others. Trade flow disruptions have occurred during 2022 related to China’s unofficial ban on Australian coal and sanctions imposed on Russian coal imports.
Major international direct competitors (listed alphabetically) include Anglo American, BHP, Glencore, Jellinbah, KRU, Shanxi Coking Coal Group,American; Arch Resources, Inc.; BHP; Foxleigh; Glencore; Jellinbah; KRU; Stanmore; Teck Resources,Resources; Warrior Met Coal; Whitehaven Coal LimitedLimited; and Yancoal Australia Ltd, and , among others.
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Cybersecurity Risk Management
| Peabody | ||
As of December 31, 2022, approximately 3,600 of Peabody’s employees are located in the U.S., with the remainder primarily located in Australia. About 94% of its team members work for mine operations in the U.S. and Australia, while the remaining are based out of its global headquarters in St. Louis or its business offices in Brisbane and Beijing.
Peabody strives to create a strong, united workforce with a commitment to safety as a way of life. In 2022, the Company achieved a global safety incidence rate of 1.13 incidents per 200,000 hours worked, which was 59% better than the 2022 U.S. industry average incidence rate of 2.77 incidents per 200,000 hours worked per the Mine Safety and Health Administration (MSHA).
Peabody strives to offer an inclusive work environment and engages, recognizes and develops employees. Peabody seeks a workforce that is comprised of diverse backgrounds, thoughts and experiences as a means to drive innovation and excellence within its business, and has formalized inclusion programs and training in policy and practice. Such diversity may also serve to mitigate risks to the business in the current tight labor market. The Company strives to attract and retain the best people, develop their potential and align their skills to important initiatives and activities. Peabody believes in fostering an inclusive work environment built on mutual trust, respect and engagement. Peabody invests in its employees through health and wellness programs, competitive total rewards and development opportunities. Peabody actively seeks employees' feedback, including through surveys and focus groups on its employee value proposition.
The typical Peabody employee has approximately seven years of experience with the company, and more than 47% of all Peabody employees remain employed with the company for more than five years. The Company offers a variety of learning events, including mentoring and development programs to aid its employees in their career growth. During the past five years, approximately 27% of open positions and 64% of director and above positions have been filled by internal candidates through promotions and lateral career development opportunities.
Information About Our Executive Officers
Set forth below are the names, ages and positions of ourPeabody’s executive officers. Executive officers are appointed by, and hold office at the discretion of, ourPeabody’s Board of Directors, subject to the terms of any employment agreements.
| Name | Age (1) | Position (1) | ||||||||||||
| President and Chief Executive Officer | ||||||||||||||
| Mark A. Spurbeck | ||||||||||||||
| Executive Vice President and Chief | ||||||||||||||
| Executive Vice President and Chief Operating Officer | ||||||||||||||
| Marc E. Hathhorn | President - U.S. Operations | |||||||||||||
| Jamie Frankcombe | 62 | President - Australian Operations | ||||||||||||
(1) As of February 18, 2020.17, 2023.
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James C. Grech was named our President and Chief Operating Officer in August 2013; our President, Chief Executive Officer-elect and a director in January 2015; and ourPeabody’s President and Chief Executive Officer in May 2015. Mr. Kellow’s careerJune 2021. He has over 30 years of experience enables him to provide the Company with valuable insights from miner, competitor fuel and industrial customer perspectives. From 1985 to 2013, he worked for BHP Ltd. in the United States, Australianatural resources industry. Mr. Grech served as Chief Executive Officer and South America.a member of the Board of Directors of Wolverine Fuels, LLC, a thermal coal producer and marketer based in Sandy, Utah, from July 2018 until May 2021. Prior to joining Wolverine Fuels, LLC, Mr. Kellow hasGrech served as President of Nexus Gas Transmission from October 2016 to July 2018, and previously held chief executive leadership, operatingthe position of Chief Commercial Officer and Executive Vice President of Consol Energy. Mr. Grech brings a strong operational, commercial and financial rolesbackground in globalboth mining and other energy business in the coal, copper, nickel, aluminum, steel, oiloperations and gas sectors.has extensive utilities and capital markets experience. He serves as Chairman of the World Coal Association, a director and executive committee member of the U.S. National Mining Association and the Vice Chairman of the International Energy Agency Coal Industry Advisory Board.Blue Danube. Mr. Kellow is a graduate of the Advanced Management Program at the University of Pennsylvania’s Wharton School of Business,Grech holds a MasterBachelor of Business Administration DegreeScience in Electrical Engineering from Lawrence Technological University and a Bachelor’s Degree in Commercean MBA from the University of Newcastle. He also holds an honorary Doctor of Science degree from the South Dakota School of Mines and Technology.Michigan.
Mark A. Spurbeck was named our InterimPeabody’s Executive Vice President and Chief Financial Officer in June 2020, after serving in an interim capacity from January 2020 through June 2020. He oversees finance, treasury, tax, internal audit, financial reporting, financial planning, risk and mine finance, corporate accounting functions, investor relations and corporate communications, information technology and shared services. Mr. Spurbeck has more than 2025 years of accounting and financial experience, most recently serving as the Company’s Senior Vice President and Chief Accounting Officer since March 2018. In this role, he has overseen Peabody’s finance, treasury, tax, internal audit, financial reporting and corporate accounting functions.from early 2018 to January 2020. Prior to joining Peabody, Mr. Spurbeck served as Vice President of Finance and Chief Accounting Officer at Coeur Mining, Inc., a diversified precious metals producer, from March 2013 to January 2018. He also previously held multiple financial positions at Newmont Mining Corporation, a leading gold and copper producer, including Group Executive, Assistant Controller. Mr. Spurbeck also previously served in several financial positions at First Data Corporation, a financial services company, and Deloitte LLP, an international accounting, tax and advisory firm. Mr. Spurbeck is a Certified Public Accountant and holds a Bachelor’s Degree in Accounting from Hillsdale College.
Scott T. Jarboe was named Peabody’s Chief Administrative Officer and Corporate Secretary in November 2021 after serving as Chief Legal Officer and Corporate Secretary since March 2020. He leads the Company’s global human resources, legal, government affairs, and ethics and compliance functions. Mr. Jarboe joined Peabody in 2010 and has served in a variety of legal roles. Previously, Mr. Jarboe practiced law with Husch Blackwell LLP and Bryan Cave LLP. Mr. Jarboe holds a Bachelor of Arts Degree from Louisiana Tech University.the University of Kansas, a Master’s Degree from the University of Missouri – Kansas City and a Juris Doctor degree from Washington University School of Law.
Marc E. Hathhorn was named ourPeabody’s President - AustralianU.S. Operations in August 2019.November 2021. He has executive responsibility for our Australianthe Company’s U.S. operating platform, which includes overseeing the areasleadership of health, safety and safety, operations,environment, people, operational performance and product delivery and support functions.delivery. Mr. Hathhorn has more than 30 years of experience in mining engineering and operations in North and South America.America and in Australia. Mr. Hathhorn joined usPeabody in 2011 as our Senior Vice President - Midwest Operations, and subsequently served as our Group Executive - Americas Operations Support from 2013 to 2016, and Group Executive - Americas Operations from 2016 to 2019 and President - Australian Operations until assuming his current role. Previously, Mr. Hathhorn held various leadership positions with Drummond LTD in South America, including Mine Operations Superintendent, Port Manager, and Vice President - Mining Operations. Prior to joining Drummond LTD, Mr. Hathhorn held various engineering and supervisory positions with Newmont Gold Corporation. Mr. Hathhorn holds a Bachelor of Science Degree in Mining Engineering from the University of Idaho, College of Mines.
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Patrick J. Forkin III was named Chief Development Officer in July 2022 after serving as Senior Vice President - Corporate Development and Strategy since November 2017. He leads global strategy, mergers and acquisitions, portfolio management, U.S. thermal coal sales and renewable energy development. Mr. Forkin joined Peabody in 2010 and has served in a variety of roles. He has an extensive background in corporate finance, the District Court entered an order dismissing the Ad Hoc Committee’s appeal,energy industry, mergers and acquisitions and equity market research. Prior to joining Peabody, Mr. Forkin was in the alternative, affirming the order confirming the Plan. On January 26, 2018, the Ad Hoc Committee appealed the District Court’s order to the United States Court of Appeals for the Eighth Circuit (the Eighth Circuit). In its appeal, the Ad Hoc Committee asked the Eighth Circuit to award the Ad Hoc Committee members either unspecified damages or the right to buy an unspecified amount of Company stocksenior leadership roles at a discount. Oral argument onU.S. solar development company and investment banking firms specializing in renewable and conventional energy. He spent the appeal was held April 16, 2019,first nine years of his career at Deloitte LLP. Mr. Forkin holds a Bachelor of Science degree in Accountancy from the University of Illinois at Urbana-Champaign and the Eighth Circuit issuedis a unanimous opinion in Peabody’s favor on August 9, 2019. The Ad Hoc Committee did not seek rehearing or petition the Supreme Court for certiorari by the deadline of November 7, 2019.Certified Public Accountant (inactive).
Regulatory Matters — U.S.
Federal, state and local authorities regulate the U.S. coal mining industry with respect to matters such as employee health and safety, permitting and licensing requirements, air quality standards, water pollution, plant and wildlife protection, the reclamation and restoration of mining properties after mining has been completed, the discharge of materials into the environment, surface subsidence from underground mining and the effects of mining on groundwater quality and availability. In addition, the industry is affected by significant requirements mandating certain benefits for current and retired coal miners. Numerous federal, state and local governmental permits and approvals are required for mining operations. We believePeabody believes that we haveit has obtained all permits currently required to conduct ourits present mining operations.
Mine Safety and Health
In Part I, Item 4. “Mine Safety Disclosures” and in Exhibit 95 to this Annual Report on Form 10-K, we providethe Company provides additional details on MSHA compliance.
Black Lung (Coal Workers’ Pneumoconiosis)
Black Lung Benefits. Under the U.S. Black Lung Benefits Revenue Act of 1977 and the Black Lung Benefits Reform Act of 1977, as amended in 1981, each U.S. coal mine operator who was the last to employ a claimant for a cumulative year of employment, with the last day worked for the operator after July 1, 1973, must pay federal black lung benefits and medical expenses to claimants whose claims for benefits are allowed. Coal mine operators must also make payments to a trust fund for the payment of benefits and medical expenses to claimants who last worked in the coal industry prior to July 1, 1973. Historically, very few of the miners who sought federal black lung benefits were awarded these benefits; however, the approval rate has increased following implementation of black lung provisions contained in the Affordable Care Act. The trust fund has been funded by an excise tax on U.S. production. In 2008, the excise tax rates were set through December 31, 2018 at $1.10 per ton for deep-mined coal and up to $0.55 per ton for surface-mined coal, neither amount to exceed 4.4% of the gross sales price. On January 1, 2019 the rate reverted back to $0.50 per ton of underground coal and $0.25 per ton of surface coal, not to exceed 2% of the gross sales price. In December of 2019, legislation was passed that increased the rate for the year ending December 31, 2020. The enacted legislation mandates the previous rates of $1.10 per ton for deep-mined coal and up to $0.55 per ton for surface-mined coal, neither amount to exceed 4.4% of the gross sales price.
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The trust fund has been funded by an excise tax on U.S. production. As a material impactresult of legislation enacted in December 2020, the excise tax rates were set at 4.4% of the gross sales price not to exceed $1.10 per ton of underground coal and $0.55 per ton of surface coal for the year ending December 31, 2021. This enacted legislation expired on our costs expendedDecember 31, 2021 and the excise tax rates reverted back to 2% of the gross sales price not to exceed $0.50 per ton of underground coal and $0.25 per ton of surface coal. Effective October 1, 2022, the excise tax rates reverted back to 4.4% of the gross sales price not to exceed $1.10 per ton of underground coal and $0.55 per ton of surface coal due to the enactment of the Inflation Reduction Act of 2022.
Peabody recognized expense related to the tax of $32.4 million, $51.5 million and $53.3 million for the years ended December 31, 2022, 2021 and 2020, respectively. During the year ended December 31, 2022, Peabody recognized additional expense of approximately $8 million as a result of the higher excise tax rates.
Black Lung Benefits Act Self-Insurance Requirements. The Black Lung Benefits Act requires each coal mine operator to secure the payment of its potential benefits liability by either qualifying as a self-insurer or by purchasing and maintaining a commercial insurance contract. The Department of Labor’s (DOL) Office of Workers’ Compensation Programs (OWCP) is responsible for authorizing coal mine operators to self-insure and for setting the security amounts. As part of its ongoing efforts to reform the self-insurance program to ensure that operators are adequately securing their liabilities, the OWCP proposed a rule in association withJanuary 2023 to update its regulations for authorizing operators to self-insure and for determining appropriate security amounts. The public comment period for the federalproposed rule ends March 20, 2023.
A change in requirements for security posted to self-insure black lung program.liabilities could result in the Company being required to post additional security for its obligations. At the request of OWCP, the Company recently refiled its application for self-insurance.
Environmental Laws and Regulations
Surface Mining Control and Reclamation Act. In the U.S., the Surface Mining Control and Reclamation Act of 1977 (SMCRA), which is administered by the Office of Surface Mining Reclamation and Enforcement (OSMRE), established mining, environmental protection and reclamation standards for surface mining and underground mining. Mine operators must obtain SMCRA permits and permit renewals for mining operations from the OSMRE or from the respective state regulatory authority. Where state regulatory agencies have adopted federal mining programs under SMCRA, the state becomes the primary regulatory authority, with oversight from OSMRE. Except for Arizona, statesStates in which we havePeabody has active mining operations have achieved primacy control of enforcement through federal authorization. In Arizona, we minewhere Peabody performs reclamation work on tribal lands, and arethe Company is regulated by the OSMRE because the tribes do not have SMCRA authorization.
SMCRA provides for three categories of bonds: surety bonds, collateral bonds and self-bonds. A surety bond is an indemnity agreement in a sum certain payable to the regulatory authority, executed by the permittee as principal and which is supported by the performance guarantee of a surety corporation. A collateral bond can take several forms, including cash, letters of credit, first lien security interest in property or other qualifying investment securities. A self-bond is an indemnity agreement in a sum certain executed by the permittee or by the permittee and any corporate guarantor made payable to the regulatory authority.
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After a permit application is prepared and submitted to the regulatory agency, it goes through a completeness and technical review. Public notice of the proposed permit is given for a comment period before a permit can be issued. Regulatory authorities have considerable discretion in the timing of the permit issuance and the public has the right to comment on and otherwise engage in the permitting process, including public hearings and through intervention in the courts. Before a SMCRA permit is issued, a mine operator must submit a bond or other form of financial security to guarantee the performance of reclamation bonding requirements.
In situations where ourthe Company’s coal resources are federally owned, the U.S. Bureau of Land Management oversees a substantive exploration and leasing process. If surface land is managed by the U.S. Forest Service, that agency serves as the cooperating agency during the federal coal leasing process. Federal coal leases also require an approved federal mining permit under the signature of the Assistant Secretary of the Department of the Interior.
The SMCRA Abandoned Mine Land Fund requires a fee on all coal produced in the U.S. The proceeds are used to rehabilitate lands mined and left unreclaimed prior to August 3, 1977 and to pay health care benefit costs of orphan beneficiaries of the Combined Fund created by the Coal Industry Retiree Health Benefit Act of 1992. The fee amount can change periodically based on changes in federal legislation. Pursuant to the Tax Relief and Health Care Act of 2006, from October 1, 2012 through September 30, 2021, the fee iswas $0.28 and $0.12 per ton of surface-mined and underground-mined coal, respectively. WeAs a result of the Abandoned Mine Land Reclamation Amendments of 2021, which Congress enacted on November 15, 2021 as part of the Infrastructure Investment and Jobs Act, from October 1, 2021 through September 30, 2034, the fee is $0.224 and $0.096 per ton of surface-mined and underground-mine coal, respectively. The Company recognized expense related to the fees of $36.5$21.7 million, $40.9 million, $31.6$27.0 million and $10.3$28.4 million for the years ended December 31, 20192022, 2021 and 2018, the period April 2 through December 31, 2017 and the period January 1 through April 1, 2017,2020, respectively.
Clean Air Act (CAA). The CAA, enacted in 1970, and comparable state and tribal laws that regulate air emissions affect ourthe Company’s U.S. coal mining operations both directly and indirectly.
The EPA also proposed in 2020 to retain the particulate matter (PM) NAAQS last revised in 2012. On December 18, 2020, the EPA issued a final rule to retain both the primary annual and 24-hour PM standards for fine particulate matter (PM2.5) and the primary 24-hour standard for coarse particulate matter (PM10) and secondary PM10 standards. This rule has also been challenged in the D.C. Circuit by several states and environmental organizations. The case is additionally considering revisionscurrently in abeyance following a motion filed by the EPA to the 2015 PM NAAQS as partallow for review of the periodic review process required bystandards. On January 6, 2023, the CAA, with any revisionsEPA proposed to lower the standards projected for late 2020,level of the same timeframe as it contemplates possible revisions forannual PM2.5 NAAQS from 12.0 ug/m3 to within the 2015 ozone NAAQS. range of 9.0 to 10.0 ug/m3.
More stringent PM or ozone standards would require new state implementation plans to be developed and filed with the EPA and may trigger additional control technology for mining equipment or result in additional challenges to permitting and expansion efforts. This could also be the case with respect to the implementation for other NAAQS for nitrogen oxidedioxide (NO2) and SOsulfur dioxide (SO2), although these standards are not subject to a statutorily-required review until 2023 for NO2 although the EPA promulgated a final rule on March 18, 2019 (84 Fed. Reg. 9866) that retains, without revision, the existing NAAQSand 2024 for SO2 of 75 ppb averaged over an hour.2.
This rule requires that newly-constructed fossil fuel-fired steam generating units achieve an emission standard for carbon dioxide of 1,400 lb carbon dioxide per megawatt-hour gross output (CO2/MWh-gross). The standard (known as the Best System of Emission Reduction (BSER)) is based on the performance of a supercritical pulverized coal boiler implementing partial carbon capture, utilization and storage (CCUS). Modified and reconstructed fossil fuel-fired steam generating units must implement the most efficient generation achievable through a combination of best operating practices and equipment upgrades, to meet an emission standard consistent with best historical performance. Reconstructed units must implement the most efficient generating technology based on the size of the unit (supercritical steam conditions for larger units, to meet a standard of 1,800 lb CO2/MWh-gross, and subcritical conditions for smaller units to meet a standard of 2,000 lb CO2/MWh-gross).
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Numerous legal challenges to the final rule were filed in the D.C. Circuit. Sixteen separate petitions for review were filed, and the challengers include 25 states, utilities, mining companies (including Peabody), labor unions, trade organizations and other groups. The cases were consolidated under the case filed by North Dakota (D.C. Cir. No. 15-1381). Four additional cases were filed seeking review of the EPA’s denial of reconsideration petitions in a final action published in the May 6, 2016 Federal Register entitled “Reconsideration of Standards of Performance for Greenhouse Gas Emissions From New, Modified, and Reconstructed Stationary Sources: Electric Generating Units; Notice of final action denying petitions for reconsideration.” Pursuant to an order of the court, these cases remain in abeyance, subject to requirements for the EPA to file 90-day status reports. Thus, the NSPS remains in effect.
On December 6,20, 2018, the EPA proposed to revise the 2015 NSPS to modify the minimum requirements for newly constructed coal-fired units from partial carbon capture and storage to efficiency-based standards. The proposal now defines(83 Fed. Reg. 65,424 (Dec. 20, 2018)). In contrast to the Best System of Emission Reduction (BSER)2015 rule, the proposed rule defined BSER as the most efficient demonstrated steam cycle in combination with the best operating practices. The EPA has notedindicated that the primary reason for this proposed revision isrevising BSER was the high costscost and limited geographic availability of carbon capture and storage technology. The comment periodStatus reports filed with the D.C. Circuit in North Dakota v. EPA indicate that litigation on the 2015 rule should remain in abeyance pending the EPA’s action on the 2018 proposed rule concluded on February 19, 2019.rule.
EPA Regulation of Greenhouse Gas Emissions from Existing Fossil Fuel-Fired EGUs. On October 23, 2015, the EPA published a final rule in the Federal Register regulating greenhouse gas emissions from existing fossil fuel-fired EGUs under Section 111(d) of the CAA (80 Fed. Reg. 64,662 (Oct. 23, 2015)). The rule (known as the Clean Power Plan or CPP) established emission guidelines for states to follow in developing plans to reduce greenhouse gas (GHG) emissions from existing fossil fuel-fired EGUs. The CPP required that the states individually or collectively create systems that would reduce carbon emissions from any EGU located within their borders by 28% in 2025 and 32% in 2030 (compared with a 2005 baseline).
The final ACE rule sets emissions guidelines for greenhouse gasGHG emissions from existing EGUs based on usinga determination that efficiency heat rate improvements as “Best System of Emission Reduction” measures. The EPA’s final rule also revisesconstitute the CAA Section 111(d) regulations to give the states greater flexibility on the content and timing of their state plans. Proposed revisions to the regulations under the New Source Review (NSR) program that were part ofBSER. Numerous petitions for review challenging the ACE proposalRule were separated, and the EPA indicated that it intends to take final action on the proposed NSR program reforms at a later date.
On October 29, 2021, the Supreme Court of the United States (Supreme Court) granted certiorari in four consolidated matters seeking review of the D.C. Circuit’s opinion vacating the ACE rule and invalidating the repeal of the CPP. On June 30, 2022, the Supreme Court issued its opinion in West Virginia v. EPA, No. 20-1530. The Supreme Court ruled that the EPA does not have Congressional authority under Section 111(d) of the CAA to limit emissions at existing power plants through generation shifting to other fuels and/or renewable energy, but still can regulate emissions at plants by emissions reductions technologies as the EPA has done in the past. The D.C. Circuit’s opinion was reversed and remanded, leaving neither the CPP including Peabody, filed a motion to dismiss, which the court granted in September 2019. Meanwhile, challengers toor the ACE Rule have filed petitionsin effect. Thus, it will be necessary for judicial review, and thatthe EPA to initiate new litigation is expectedrulemaking in order to control GHG emissions from EGUs using section 111(d) of the CAA. The EPA tentatively plans to propose emission guidelines for EGUs in 2023. The Company will continue into 2020.to monitor EPA rulemaking in this regard.
EPA’s Greenhouse Gas Permitting Regulations for Major Emission Sources. In May 2010, the EPA published final rules requiring permitting and control technology requirements for greenhouse gases under the Prevention of Significant Deterioration (PSD) and Title V permitting programs that apply to stationary sources of air pollution. The EPA determined that these requirements were “triggered” by the EPA’s prior regulation of greenhouse gases from motor vehicles. These rules were subsequently upheld by the D.C. Circuit on June 26, 2012. On June 23, 2014, however, the U.S. Supreme Court ruled that the EPA could not require PSD and Title V permitting for greenhouse gases emitted from stationary sources if those sources were not otherwise considered to be “major sources” of conventional pollutants for purposes of PSD and Title V (known as Step 2 sources). In accordance with that decision, the D.C. Circuit vacated the federal regulations that implemented Step 2 of the Greenhouse Gas Tailoring Rule in 2015. Subsequently, the EPA removed the vacated elements from its rules to ensure that neither the PSD nor Title V rules require a source to obtain a permit solely because the source emits or has the potential to emit greenhouse gases above the applicable thresholds. The EPA therefore no longer has the authority to conduct PSD permitting for Step 2 sources, nor can the EPA approve provisions submitted by a state for inclusion in its state implementation plan (SIP) providing this authority.
Cross State Air Pollution Rule (CSAPR) and CSAPR Update Rule. On July 6,In 2011, the EPA finalized the CSAPR, which requires the District of Columbia and 27 states from Texas eastward (not including the New England states or Delaware) to reduce power plant emissions that cross state lines and significantly contribute to ozone and/or fine particle pollution in other states. Following litigation in the D.C. Circuit and U.S. Supreme Court, the first phase of the nitrogen oxide and SO2 emissions reductions required by CSAPR commenced in January 2015; further reductions of both pollutants in the second phase of CSAPR became effective in January 2017. The EPA subsequently revised CSAPR requirements for the state of Texas to remove that state from second phase requirements regarding SO2 (82 Fed. Reg. 45,481 (Sept. 29, 2017)).
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In April 2021, the EPA published a final rule in the Federal Register to address the D.C. Circuit remand. This rule imposed further reductions of NOx emissions in 12 states that were subject to the original 2016 rule, which was based on the 2008 ozone NAAQS.
In 2018,the same rule, the EPA alsodetermined that 9 states did not significantly contribute to downwind nonattainment and/or maintenance issues and therefore did not require additional emission reductions. The EPA subsequently issued a final determination thatFederal Implementation Plans (FIPs) to lower state ozone season NOx budgets in 2021 to 2024 in the existing CSAPR Update fully addressedaffected states. A petition for review challenging the CAA’s “good neighbor” requirements for 20 states with respect to the 2008 NAAQS for ground-level ozone. (83 Fed. Reg. 65,878 (Dec. 21, 2018)).This determination2021 rule was also challengedfiled in the D.C. Circuit (No. 19-1019). On October 1, 2019,Circuit. Briefing is completed and oral arguments were held September 28, 2022, but this does not stay the D.C. Circuit issued a judgment vacating this rule on the basiseffectiveness of the court’s decisionrule.
On April 6, 2022, the EPA proposed FIPs to address regional ozone transport for the 2015 ozone NAAQS. The proposed rule would result in new ozone season emission budgets for NOWisconsin v.x in 25 states, including four Western states, and additionally contains provisions that would require daily “backstop” emission limits for coal-fired power plants over 100 megawatts. The proposed rule would also set first-time limits on certain industrial sources. The EPA. At this time, it is unknown whether rehearing estimates that by 2026 the compliance cost will be sought.$1.1 billion. These emission limitations would apply in addition to requirements contained in State Implementation Plans to control ozone precursors in affected states, although states have the option to replace these limits with equally strict or more stringent limitations.
Mercury and Air Toxic Standards (MATS). The EPA published the final MATS rule in the Federal Register on February 16,in 2012. The MATS rule revised the NSPS for nitrogen oxides,NOx, SO2 and PM for new and modified coal-fueled electricity generating plants, and imposed MACTmaximum achievable control technology (MACT) emission limits on hazardous air pollutants (HAPs) from new and existing coal-fueled and oil-fueled electric generating plants. MACT standards limit emissions of mercury, acid gas HAPs, non-mercury HAP metals and organic HAPs. The rule provided three years for compliance with MACT standards and a possible fourth year if a state permitting agency determined that such was necessary for the installation of controls.
On December 27, 2018,February 9, 2022 the EPA issuedproposed a proposed revised Supplemental Cost Finding for the MATS rule that wouldto revoke the determination2020 finding and to reaffirm the agency’s 2016 finding that regulating HAPs from coal-fired power plants isit remains “appropriate and necessary” to regulate HAP emissions from coal- and oil-fired power plants under Section 112(n)(1)(A)112 of the CAA. In the same proposal, the EPA solicited comments on the performance and cost of new or improved technologies to control HAPs from these power plants as part of the agency’s review of related residual risk and technology review standards.
Regional Haze. The Clean Air Act contains a national visibility goal for the “prevention of any future, and the remedying of any existing, impairment of visibility in Class I areas which impairment results from manmade air pollution.” The EPA promulgated comprehensive regulations in 1999 requiring all states to submit plans to address regional haze that could affect 156 national parks and wilderness areas, including requirements for certain sources to install the best available retrofit technology and for states to demonstrate “reasonable progress” towards meeting the national visibility goal. States are required to revise plans every 10 years.
New Source Review (NSR). The Clean Air Act imposes permitting requirements when a new proposed finding was based onsource undergoes construction or when an EPA assessment that health and environmental benefits from the MATS rule thatexisting source is reconstructed or undergoes a major modification. These requirements are not directly related to mercury pollution should not be includedcontained in the benefit portion of the analysis. In the new proposed cost-benefit analysis,CAA’s PSD and Nonattainment New Source Review (NNSR) programs, generally referred to as NSR. On August 4, 2020, the EPA foundreleased a guidance memorandum concerning implementation of plantwide applicability limitations (PALs) (Guidance on Plantwide Applicability Limitation Provisions Under the costs “grossly outweigh” any possible benefits. The comment period for this proposed rule closed in spring 2019 with overNew Source Review Regulations). PALs allow sources to make physical and operational changes under a half million public comments filed. The final rule was expected in the fall but stalled after being sent to the White House in October 2019 for final review before public release. It is unclear when the final rule will be published.plantwide emission limit without “triggering” NSR.
The EPA Science Advisory Board, made uphas also taken action on a number of non-EPA scientistsdifferent rules and experts who reviewguidance affecting the EPA’s basis for regulatory decisions, recommended in December 2019 thatinterpretation and application of NSR. In a final rule (83 Fed. Reg. 57,324 (Nov. 15, 2018)), the EPA conductcompleted reconsideration of a new risk assessment2009 petition to clarify when certain actions must be “aggregated” for purposes of determining whether these actions are part of a single project to which NSR applies. The EPA has additionally published guidance on the definition of “ambient air” (Revised Policy on Exclusions from “Ambient Air,” Dec. 2, 2019) and guidance concerning when multiple air pollution-emitting activities may be considered to be “adjacent” so that they should be considered to be a single source (Interpreting “Adjacent” for New Source Review and Title V Source Determinations in All Industries Other Than Oil and Gas, Nov. 26, 2019). Additional memorandum and applicability determinations have also been made that address other NSR issues and the rule.EPA has also taken steps to review and potentially revise previously issued rules and guidance, including those related to project emissions accounting and fugitive emissions. PSD rules, guidance and memorandum may affect the construction, reconstruction and modification of sources and the level of pollution control requirements that will be necessary on a case-by-case basis.
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Federal Coal Leasing Moratorium. MoratoriumPresident Trump’s. The Executive Order on Promoting Energy Independence and Economic Growth (EI Order), signed on March 28, 2017, lifted the Department of Interior’s federal coal leasing moratorium and rescinded guidance on the inclusion of social cost of carbon in federal rulemaking. Following the EI Order, the Interior Secretary issued Order 3349 ending the federal coal leasing moratorium. Environmental groups took the issue to court (District of Montana) and in September 2018, WyomingApril 2019, the court held the lifting of the moratorium triggered National Environmental Policy Act (NEPA) review. On May 22, 2020, the court held that the Department of the Interior’s issuance of an Environmental Assessment and Montana opposedFinding of No Significant Impact (FONSI) remedied the suits inprior NEPA violations. Thereafter, environmental groups amended their complaint to challenge the Environmental Assessment and FONSI. On August 12, 2022, the court invalidated the Environmental Assessment and defended againstFONSI and reinstated the freeze possibly being reinstated. This litigationmoratorium until completion of a sufficient NEPA analysis. The August 2022 decision is ongoing.currently on appeal to the U.S. Court of Appeals for the Ninth Circuit.
Clean Water Act (CWA). The CWA of 1972 directly impacts U.S. coal mining operations by requiring effluent limitations and treatment standards for wastewater discharge from mines through the National Pollutant Discharge Elimination System (NPDES). Regular monitoring, reporting and performance standards are requirements of NPDES permits that govern the discharge of water from mine-related point sources into receiving waters.
The U.S. Army Corps of Engineers (Corps) regulates certain activities affecting navigable waters and waters of the U.S., including wetlands. Section 404 of the CWA requires mining companies to obtain permits from the Corps to place material in or mine through jurisdictional waters of the U.S.
States are empowered to develop and apply water quality standards. These standards are subject to change and must be approved by the EPA. Discharges must either meet state water quality standards or be authorized through available regulatory processes such as alternate standards or variances. Standards vary from state to state. Additionally, through the CWA Section 401 certification program, state and tribal regulators have approval authority over federal permits or licenses that might result in a discharge to their waters. State and tribal regulators consider whether the activity will comply with their water quality standards and other applicable requirements in deciding whether or not to certify the activity. On August 9, 2019, theThe EPA issued a proposedfinal rule intended to clarify the scope of the state or tribal regulators’ authorityin 2020 that if adopted in its current form, would in effectcould limit state and tribal regulators’ authority by allowing the EPA to certify projects over state or tribal regulator objections.objections in some circumstances. That rule was temporarily vacated by a district court, but a Supreme Court order on April 7, 2022, effectively reinstated the rule. The comment periodEPA issued another proposal in June 2022 that would supersede the 2020 rule and expand state and tribal regulators’ authority to review activities that require federal permits or licenses and to impose conditions they believe are necessary to ensure compliance with water quality requirements. Comments for this proposed rule closed on October 21, 2019.
CWA Definition of waters protected under the CWA (commonly called the Waters“Waters of the United States, or WOTUS) (WOTUS Rule), was published by the EPA and the Corps in June 2015. Several states and others subsequently filed lawsuits challenging the WOTUS Rule. On October 22, 2019, the EPA and the Corps jointly published a final rule, which became effective on December 23, 2019, repealing the WOTUS Rule and recodifying the regulatory definitions of WOTUS that existed prior to the implementation of the WOTUS Rule. Several states subsequently filed a lawsuit against the EPA, claiming that the rollback of protections for certain U.S. waterways pursuant to the final rule is arbitrary, capricious and not in accordance with law. OnStates”. In January 23, 2020 the EPA and the Corps finalized the Navigable Waters Protection Rule to definerevise the definition of “Waters of the United States” and thereby establish the scope of federal regulatory authority under the CWA. On August 30, 2021, a federal court in Arizona vacated the Navigable Waters Protection Rule, and on September 3, 2021, the EPA and the Corps announced that they had “halted implementation” of the rule nationwide and that they are interpreting “Waters of the United States” consistent with the pre-2015 regulatory framework. On December 30, 2022, the agencies released the pre-publication version of a final rule that formally repeals the Navigable Waters Protection Rule and codifies a revised definition of “Waters of the United States” that is generally consistent with the pre-2015 regulatory framework that they are currently implementing. The final rule will become effective 60 days after publicationwas published in the Federal Register. Once effective, it replacesRegister on January 18, 2023 and takes effect on March 20, 2023. In addition, the rule publishedSupreme Court is currently considering Sackett v. EPA, No. 21-454, a case involving the scope of federal regulatory authority over wetlands. The Court heard oral arguments on October 22, 2019.3, 2022, and the opinion is forthcoming. Depending on the outcome of that case, the agencies may need to revisit the most recent rulemaking.
Effluent Limitations Guidelines for the Steam Electric Power Generating IndustryIndustry. . On September 30, 2015, the EPA published a final rule setting new or additional requirements for various wastewater discharges from steam electric power plants. The rule set zero discharge requirements for some waste streams, as well as new, more stringent limits for arsenic, mercury, selenium and nitrogen applicable to certain other waste streams. On April 12, 2019, the U.S. Court of Appeals for the Fifth Circuit agreed with environmental groups that the portions of the rule regulating legacy wastewater and residual combustion leachate are unlawful. The Court vacated those portions of the rule. On November 22, 2019,October 13, 2020, the EPA issued a proposedfinal rule to reviserevising the technology-based effluent limitations guidelines and standards for the steam electric power generating point source category applicable to flue gas desulfurization wastewater and bottom ash transport water. However, on August 3, 2021, the EPA announced it is undertaking a supplemental rulemaking to “strengthen certain discharge limits” applicable to steam electric power plants. The comment period for this proposed rule closed on January 21, 2020. IfEPA expects to issue that proposal in early 2023. As finalized, the proposed rule is adopted in its current form, therevised effluent limitations guidelines willcould significantly increase costs for many coal-fired steam electric power plants.
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National Environmental Policy Act (NEPA). NEPA, signed into law in 1970, requires federal agencies to review the environmental impacts of their decisions and issue either an environmental assessment or an environmental impact statement. WePeabody must provide information to agencies when we proposeit proposes actions that will be under the authority of the federal government. The NEPA process involves public participation and can involve lengthy timeframes. The White House Council on Environmental Quality (CEQ) issued an Advance Noticea final rule comprehensively updating and modernizing its longstanding NEPA regulations on July 16, 2020. That final rule sought to reduce unnecessary paperwork, burdens and delays, promote better coordination among agency decision makers, and clarify scope of Proposed RulemakingNEPA reviews, among other things. States and environmental groups have filed several lawsuits challenging the final rule. On April 20, 2022, however, the CEQ published the final Phase 1 rule that partially amended the 2020 rule by restoring key provisions of the pre-2020 NEPA regulations. The CEQ plans to propose a Phase 2 rule in June 2018 seeking commentthe near future that makes broader changes to the 2020 rule. Separately, the CEQ published NEPA Guidance on a numberConsideration of ways to streamlineGreenhouse Gas Emissions and improveClimate Change on January 9, 2023. The interim guidance was effective immediately, though the NEPA process. The comment period closed in August��2018. Itagency is unclear how far reachingaccepting comments on the changes will be and if they will be able to withstand expected court challenges.guidance.
Resource Conservation and Recovery Act (RCRA). RCRA, which was enacted in 1976, affects U.S. coal mining operations by establishing “cradle to grave” requirements for the treatment, storage and disposal of hazardous wastes. Typically, the only hazardous wastes generated at a mine site are those from products used in vehicles and for machinery maintenance. Coal mine wastes, such as overburden and coal cleaning wastes, are not considered hazardous wastes under RCRA.
Subtitle C of RCRA exempted fossil fuel combustion wastes from hazardous waste regulation until the EPA completed a report to Congress and made a determination on whether the wastes should be regulated as hazardous. On December 19, 2014, the EPA announced the final rule on coal combustion residuals (CCR or coal ash). As finalized, the rule continues the exemption of CCR from regulation as a hazardous waste, but does impose new requirements at existing CCR surface impoundments and landfills that will need to be implemented over a number of different time-frames in the coming months and years, as well as at new surface impoundments and landfills. The U.S. Court of Appeals for the D.C. Circuit held that certain provisions of the EPA’s CCR rule were not sufficiently protective, and it invalidated those provisions. On December 2, 2019, the EPA issued a proposed rule to implement amended rules regarding CCR in response to the court decisions. The comment period for this proposed rule closed on January 31, 2020. Generally, EPA-imposed requirements will increase the cost of CCR management, but not as much as if the rule had regulated CCR as hazardoushazardous.
Comprehensive Environmental Response, Compensation and Liability Act (CERCLA). Although generally not a prominent environmental law in the coal mining sector, CERCLA, which was enacted in 1980, nonetheless may affect U.S. coal mining operations by creating liability for investigation and remediation in response to releases of hazardous substances into the environment and for damages to natural resources. Under CERCLA, joint and several liabilities may be imposed on waste generators, site owners or operators and others, regardless of fault.
Toxic Release Inventory. Arising out of the passage of the Emergency Planning and Community Right-to-Know Act in 1986 and the Pollution Prevention Act passed in 1990, the EPA’s Toxic Release Inventory program requires companies to report the use, manufacture or processing of listed toxic materials that exceed established thresholds, including chemicals used in equipment maintenance, reclamation, water treatment and ash received for mine placement from power generation customers.
Endangered Species Act (ESA). The ESA of 1973 and counterpart state legislation is intended to protect species whose populations allow for categorization as either endangered or threatened. Changes in listings or requirements under these regulations could have a material adverse effect on ourPeabody’s costs or ourits ability to mine some of ourits properties in accordance with ourits current mining plans. The DepartmentDuring the Trump Administration, the Departments of the Interior and Commerce issued three proposedfinalized five rules in 2018 aiming to streamline and update the ESA. But in June 2021, agencies announced their plan to revise, rescind, or reinstate the rules that were finalized (or withdrawn) during the Trump Administration that conflict with the Biden Administration’s objectives. The three finalagencies plan to begin issuing proposed rules became effective on September 26, 2019.in mid-2023.
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Use of Explosives. OurPeabody’s surface mining operations are subject to numerous regulations relating to blasting activities. Pursuant to these regulations, we incurit incurs costs to design and implement blast schedules and to conduct pre-blast surveys and blast monitoring. The storage of explosives is subject to strict federal regulatory requirements. The U.S. Bureau of Alcohol, Tobacco and Firearms (ATF) regulates the use of explosive blasting materials. In addition to ATF regulation, the Department of Homeland Security is expected to finalize an ammonium nitrate security program rule. On July 30, 2019, the OSMRE officially withdrew its decision to initiate rulemaking related to emissions generated from blasting at coal mining operations. The decision cited its lack of statutory authority and the sufficiency of the existing regulatory framework.
Federal Report on Climate Change. On November 23, 2018, the U.S. Global Change Research Program, a working group comprised of 13 U.S. governmental departments and agencies, issued the Fourth National Climate Assessment. The report lists the observed effects of “increasing greenhouse gas concentrations on Earth’s climate” and enumerates the impacts of those observed effects. The report also discusses the alternatives for reducing the impacts of climate-related risks, including through mitigation and adaptation. While there are no explicit regulatory actions that flow from the issuance of the report, both the legislative and executive branches of government may rely on its conclusions to shape and justify policies and actions going forward. A Fifth National Climate Assessment is currently in development with an anticipated publication date in 2023.
SEC Climate-Related Disclosures. On March 21, 2022, the SEC proposed rules that would require public companies to disclose extensive climate-related information in certain SEC filings. Specifically, the proposed rules would add new Subpart 1500 to Regulation S-K and new Article 14 to Regulation S-X to require disclosure of climate-related risks that are reasonably likely to have a material impact on a public company’s business, results of operations, or financial condition; GHG emissions associated with a public company that includes, in many cases, an attestation report by a GHG emissions attestation provider; and climate-related financial metrics to be included in a company’s audited financial statements. The Company is currently assessing the potential impact of the proposed rules. The public comment period on the proposed rules has concluded and final rules are expected in 2023.
Inflation Reduction Act of 2022. The Inflation Reduction Act of 2022 was signed into law on August 16, 2022. Among its many provisions are programs that provide grants and other forms of direct and indirect financial assistance for the deployment of zero emission technologies as well as other actions that could affect energy markets and the future use of coal. The Company is currently assessing the potential environmental impacts of the legislation.
Regulatory Matters — Australia
The Australian mining industry is regulated by Australian federal, state and local governments with respect to environmental issues such as land reclamation, water quality, air quality, dust control, noise, planning issues (such as approvals to expand existing mines or to develop new mines) and health and safety issues. The Australian federal government retains control over the level of foreign investment and export approvals. Industrial relations are regulated under both federal and state laws. Australian state governments also require coal companies to post deposits or give other security against land which is being used for mining, with those deposits being returned or security released after satisfactory reclamation is completed.
New South Wales Coal Directions. Since 1992,The State of New South Wales (NSW) enacted the Australian courts have recognizedEnergy and Utilities Administration Amendment Act 2022 granting the State Premier and Minister for Energy the ability to issue directions in the event of a coal market price emergency (among other powers). On December 22, 2022, the State Premier declared a coal market price emergency on the basis that native titlethe declaration was necessary to landsreduce the risk that increases in coal prices could contribute to an increase in electricity prices. On December 23, 2022, Peabody and water, as recognized under the lawsa number of other coal producers in NSW were issued with directions that require those coal producers to reserve and customssell a portion of the Aboriginal inhabitantscoal produced to NSW power generators at a capped price until June 30, 2024. On January 31, 2023, amended directions were issued. The directions, as they currently stand, apply to the Wilpinjong Mine and also impose a number of Australia,additional reporting obligations with respect to coal produced from the Wilpinjong Mine. However, the NSW government is in ongoing discussions with coal producers and power generators regarding issuing additional directions. It is anticipated that these directions will not impact Wilpinjong Mine, but may have survivedrequire the reservation of coal at the Wambo Mines; however, the nature and extent of those obligations and associated reporting requirements are still evolving and require further clarification from the NSW government.
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Metropolitan Mine Stormwater Discharge. Over the past two years, there has been significantly high rainfall in New South Wales, including unprecedented rain totals at the Metropolitan Mine site. While stormwater collected at the mine site is managed through two sedimentation dams, at times the heavy rainfall has presented challenges with managing the significant volumes of stormwater, as the surface water management infrastructure has not had sufficient capacity. As a result, on multiple occasions throughout 2021 and 2022 stormwater has been discharged from the mine site. Metropolitan Collieries Pty Ltd (MCPL), a wholly-owned subsidiary of Peabody, removed accumulated material from the sedimentation dams to restore full site stormwater capacity by December 31, 2022 and has identified and is implementing additional controls for the management of sediment moving forward. Despite the measures undertaken by MCPL to manage and improve the situation, the Environment Protection Authority is currently undertaking an investigation in relation to the discharges of sediment laden water from the mine site and a review process of European settlement. These developments are supported by the federal Native Title Act which recognizes and protects native title, and under which a national register of native title claims has been established. Native title rights do not extend to minerals; however, native title rights can be affected by mining activities unless those rights have previously been extinguished, thereby requiring negotiation withMetropolitan Mine’s environmental protection license. The Environment Protection Authority is investigating potential offenses against the traditional owners (and potentiallyenvironmental protection legislation arising from the payment of compensation) prior to the grant of certain mining tenements. There is also federal and state legislation to prevent damage to Aboriginal cultural heritage and archaeological sites.discharges.
Mining Tenements and Environmental. In Queensland and New South Wales, the development of a mine requires both the grant of a right to extract the resource and an approval which authorizes the environmental impact. These approvals are obtained under separate legislation from separate government authorities. However, the application processes run concurrently and are also concurrent with any native title or cultural heritage process that is required. The environmental impacts of mining projects are regulated by state and federal governments. Federal regulation will only apply if the particular project will significantly impact a matter of national environmental significance (for example, a water resource, an endangered species or particular protected places). Environmental approvals processes involve complex issues that, on occasion, require lengthy studies and documentation.
In February 2019, the New South Wales (NSW) Land and Environment Court (LEC) upheld the government’s denial of a planning approval for a non-Peabody coal mining project (Gloucester Resources Limited v. Minister for Planning). Although the approval was refused for other reasons, the judge in that case discussed ‘Scope 3’ greenhouse gas emissions resulting from the consumption of coal to be mined under the proposed project. Such emissions are often raised as a ground of objection to Australian mining projects, including ourPeabody’s mining projects. For example, in a subsequent LEC decision (Australian Coal Alliance Incorporated v. Wyong Coal Pty Ltd), the approval of a coal mining project was confirmed after such emissions had been considered by the relevant authority. In August 2019, Peabody and Glencore received approval from the NSW Independent Planning Commission (IPC) for the United Wambo project, subject to conditions (Export Conditions) requiring the joint venture to prepare an Export Management Plan setting out protocols for using all reasonable and feasible measures to ensure that any coal extracted from the mine that is to be exported from Australia is only exported to countries that are parties to the Paris Agreement (as defined below) or countries that the NSW Planning Secretary considers to have similar policies for reducing greenhouse gas emissions. In September 2019, the IPC declined to approve a non-Peabody ‘greenfield’ coal mining project (Bylong) for various reasons, including Scope 3 greenhouse gas emissions.The applicant for that project has applied for the IPC’s decision to be judicially reviewed. The IPC subsequently approved another non-Peabody coal mining project (Rix’s Creek) without any Export Conditions. In October 2019, the NSW government introduced into Parliament proposed amendments to legislation and policy that would, if passed, have the effect of invalidating Export Conditions imposed on future NSW planning approvals, as well as no longer requiring consent authorities to consider ‘downstream emissions’ when assessing developments for the purposes of mining, petroleum production or extractive industry. The NSW government has announced changes to the IPC and planning system process which aims to improve timeframes and efficiencies for project approvals and providing more clarity on the IPC’s role in determining applications including seeking guidance on government policy. In June 2020, the NSW Government released its Strategic Statement on Coal Exploration and Mining in NSW which provides a high level framework for the government's policy approach to the future of the coal sector, as well as details of a streamlined strategic release process. The strategy identifies some potential areas for possible new coal exploration, areas that are ruled out for coal mining and areas where new coal exploration can only occur adjacent to an existing coal title via the Operational Allocation process. In December 2020, the NSW Government finalized and published the Guideline for the Competitive Allocation of Coal, which details the process for considering areas for coal exploration and allocating them by public tender.
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In New South Wales, laws and regulations related to mining include, but are not limited to, the Mining Act 1992, Work Health and Safety (Mines) Act 2013, Coal Mine Subsidence Compensation Act 2017, Environmental Planning and Assessment Act 1979 (EPA Act), Environmental Planning and Assessment Regulations 2000, Protection of the Environment Operations Act 1997, Contaminated Land Management Act 1997, Explosives Act 2003, Water Management Act 2000, Water Act 1912, Radiation Control Act 1990, Biodiversity Conservation Act 2016 (BC Act), Heritage Act 1977, Aboriginal Land Rights Act 1983, Crown Land Management Act 2016, Dangerous Goods (Road and Rail Transport) Act 2008, Fisheries Management Act 1994, Forestry Act 2012, Native Title (New South Wales) Act 1994, Biosecurity Act 2015, Roads Act 1993 and National Parks & Wildlife Act 1974.
Under the EPA Act, environmental planning instruments must be considered when approving a mining project development application. Decision makers review the significance of a resource and the state and regional economic benefits of a proposed coal mine when considering a development application on the basis that it is an element of the “public interest” consideration contained in the relevant legislation. Effective from March 1, 2018, the EPA Act was amended to introduce a number of changes to planning laws in New South Wales. The EPA Act was further amended in June 2018 to revoke a process for modifying development approvals under the former Section 75W of the EPA Act. As a result, new development approvals will need to be obtained unless the proposed project will be substantially the same development as it was when the development approval was last modified under Section 75W, in which case the existing development approval can be modified. If a new development approval is required then this could take additional time to achieve.
On August 25, 2017, the BC Act commenced in New South Wales and imposes a revised framework for the assessment of potential impacts on biodiversity that may be caused by a development, such as a proposed mining project. The BC Act requires these potential impacts on biodiversity to be offset in perpetuity, by one or more of the following means: securing land based offsets and retiring biodiversity credits, making a payment into a biodiversity conservation fund or in some cases through mine site ecological rehabilitation. The data collected from the biodiversity impact assessment process is inputted into a new offsets payment calculator in order to determine the amount payable by the proponent to offset the impacts. The proposed development can only proceed once the biodiversity offset obligations have been satisfied.
Sharma v Minister for the Environment. On March 15, 2022, the Full Court of the Federal Court of Australia overturned the decision in Sharma v Minister for the Environment [2021] FCA 560 (Sharma), a case which found in 2021 that the Federal Minister for the Environment had a duty to avoid causing personal injury or death to children in Australia as a result of carbon emissions when deciding an application to approve a coal mine expansion. In light of this decision, the Minister for the Environment no longer must consider the effects of carbon emissions when assessing referrals under the Environment Protection and Biodiversity Conservation Act 1999. However, an application by Sharma for special leave to appeal to the High Court of Australia remains probable, and the duty could be reinstated.
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Mining Rehabilitation (Reclamation). Mine reclamation is regulated by state-specific legislation. As a condition of approval for mining operations, companies are required to progressively reclaim mined land and provide appropriate bonding, or, in certain circumstances (see below in relation to the Mineral and Energy Resources (Financial Provisioning) Act 2018), make alternative financial contributions to the relevant state government as a safeguard to cover the costs of reclamation in circumstances where mine operators are unable to do so. Self-bonding is not permitted. OurPeabody’s mines provide financial assurance to the relevant authorities which is calculated in accordance with current regulatory requirements. This financial assurance is in the form of cash, surety bonds or bank guarantees which are supported by a combination of cash collateral, deeds of indemnity and guarantee and letters of credit issued under ourthe Company’s credit facility, collateralized letter of credit program and accounts receivable securitization program. We operateThe Company operates in both the Queensland and New South Wales state jurisdictions.
New South Wales Reclamation. The Mining Act 1992 (Mining Act) is administered by the Department of Planning and Environment and the New South Wales Resources Regulator and authorizes the holder of a mining tenement to extract a mineral subject to obtaining consent under the EPA Act and other auxiliary approvals and licenses.
Through the Mining Act, environmental protection and reclamation are regulated by conditions in all mining leases including requirements for the submission of a mining operations plan (MOP) prior to the commencement of operations. All mining operations must be carried out in accordance with the MOP which describes site activities and the progress toward environmental and reclamation outcomes and are updated on a regular basis or if mine plans change. The mines publicly report their reclamation performance on an annual basis.
In support of the MOP process, a reclamation cost estimate is calculated periodically to determine the amount of bond support required to cover the cost of reclamation based on the extent of disturbance during the MOP period.
Queensland Reclamation. The EP Act is administered by the Department of Environment and Science, which authorizes environmentally relevant activities such as mining activities relating to a mining lease through an Environmental Authority (EA). Environmental protection and reclamation activities are regulated by conditions in the EA. All mining operations must be carried out in a manner so as to ensure compliance with the conditions in the EA. The mines submit an annual return reporting on their EA compliance.
In November 2018, the Queensland government passed the Mineral and Energy Resources (Financial Provisioning) Act 2018 providing for a new financial assurance (FA) framework and new progressive rehabilitation requirements. The new FA framework creates a pooled fund covering most mines and most of the total industry liability, plus other options for providing FA if not part of the pooled fund (for example, allowing insurance bonds or cash). The percentage rate of the total rehabilitation cost payable into the pooled fund will take into account the financial strength of the holder of the EA for the mine and the project strength of the mine. The total rehabilitation cost is determined using an updated rehabilitation cost calculator, which no longer provides for discounting. The commencement date for the new FA framework was April 1, 2019 and there is a transitional period during which wePeabody will move each of ourits mines in Queensland into the new FA framework.
The new progressive rehabilitation requirements commenced on November 1, 2019 and require each mine, within a three-year transitional period, to establish a schedule of rehabilitation milestones covering the life of the mine, and any significant changes to the timing of rehabilitation will require regulatory approval. If there is to remain an area within the mine that does not have a post-mining land use (referred to as a non-use management area or NUMA) then each such NUMA will need to pass a public interest evaluation test as part of the approval process. An example of a NUMA is the void that remains after open-cut mining activities have been completed. Under the legislation, each current mine is exempt from the requirement to justify its NUMAs to the extent that its current approvals provide for such areas. We areThe Company is of the view that there will not be a need to seek any further regulatory approvals for any of the NUMAs at any of ourits Queensland mines.
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Residual Risks. On November 19, 2018,August 20, 2020, the Queensland government released for public consultation a discussion paperEnvironmental Protection and Other Legislation Amendment Act (Queensland) 2020 (EPOLA Act) became law, amending the residual risk framework that aims to ensure that any remaining risks on managing ‘residual risks’ of mining activities.former resource sites are appropriately identified, costed and managed. On completion of all mining activities, the holder of the EA for the mine can apply to surrender the EA once all conditions, requirements and rehabilitation obligations have been met. When approving the surrender, the government can request a residual risk payment from the holder of the EA for the mine to cover potential rehabilitation or maintenance costs incurred after the surrender has been accepted. The discussion paperIt contemplates two approaches for determining residual risk payments. Depending on the level of risk of a particular site, a cost calculator tool might be used or a panel of appropriately qualified experts might undertake a qualitative and quantitative risk assessment. Industry
Native Title and Cultural Heritage. Since 1992, the Company continueAustralian courts have recognized that native title to consultlands and water, as recognized under the laws and customs of the Aboriginal inhabitants of Australia, may have survived the process of European settlement. These developments are supported by the federal Native Title Act which recognizes and protects native title, and under which a national register of native title claims has been established. Native title rights do not extend to minerals; however, native title rights can be affected by mining activities unless those rights have previously been extinguished, thereby requiring negotiation with the government ontraditional owners (and potentially the proposed residual risk payment regime.of compensation) prior to the grant of certain mining tenements. There is also federal and state legislation to prevent damage to Aboriginal cultural heritage and archaeological sites.
Following the May 2020 destruction of caves at the Juukan Gorge in the Pilbara region of Western Australia by an iron ore mining operation, the Federal Reclamation. In February 2017,Government established a Senate Inquiry. The Senate Inquiry’s terms of reference included reviewing the effectiveness and adequacy of state and federal laws in relation to Aboriginal and Torres Strait Islander cultural heritage in each of the Australian jurisdictions; and how these cultural heritage laws might be improved to guarantee the protection of culturally and historically significant sites. Following an interim report released on December 9, 2020, the Joint Standing Committee on Northern Australia released its final report on October 18, 2021. The final report sets out three key findings and eight recommendations, including that a new framework for cultural heritage protection be implemented at a national level by way of new legislated national minimum standards for State and Territory laws. The recommendations also include that a review of the Native Title Act 1993 (Cth) be undertaken to address inequalities in the negotiating position of Aboriginal and Torres Strait Islander peoples in the future act regime, including the ‘right to negotiate’ process which is associated with the grant of certain mining tenements. On November 24, 2022, the Environment Minister announced the Australian government’s support for all but one of the recommendations from the Senate establishedInquiry (whether final responsibility for heritage protection should sit with the Indigenous Affairs Minister or the Environment Minister is still being assessed) and indicated laws to protect Aboriginal cultural heritage would be strengthened following a Committee of Inquiry into the rehabilitationfurther review of mining standards. Any legislation passed as a result of the recommendations in the final report could potentially impact the Company’s current and resources projects as it relates to Commonwealth responsibilities, for example, under the Environment Protectionfuture mining tenements and Biodiversity Conservation Act 1999. The Committee released their report in March 2019. The Committee was unable to reach unanimous agreement on a set of recommendations. It is unclear the extent to which the report will impact policy reform at a federal government level.operations.
Occupational Health and Safety. State legislation requires usPeabody to provide and maintain a safe workplace by providing safe systems of work, safety equipment and appropriate information, instruction, training and supervision. In recognition of the specialized nature of mining and mining activities, specific occupational health and safety obligations have been mandated under state legislation specific to the coal mining industry. There are some differences in the application and detail of the laws, and mining operators, directors, officers and certain other employees are all subject to the obligations under this legislation.
September 2020, Safe Work Australia (SWA) is currently reviewing thepublished its revised Workplace Exposure Standards (WES) for all airborne contaminants including welding fumes and diesel particulate matter and giving priority to the WES for coal dust and silica. The review is expected to continue until June 2020. SWA’s draft evaluation reports will include recommendations for exposure limits. The exposure limits recommended by SWA aresilica based on toxicological information and other monitoring data. SWA have recommended exposure limits of 1.5mg/1.5 milligrams per cubic meter (mg/m3) for coal dust (to apply from October 2022) and 0.05 mg/m3 for silica.silica (to apply as soon as possible). In Queensland, a new workplace exposure standard for respirable crystalline silica (eight hour time-weighted average airborne concentration of 0.05mg/m
In addition, as part of a broader review of workplace exposure standards, SWA is currently considering a proposal to reduce the time weighted average (TWA) WES for CO2 in Australian coal mines from 12,500 ppm to 5,000 ppm. Currently there is a separate TWA for CO2 in coal mines, however SWA proposes to remove this to align with a general industry standard. If implemented, the change has the potential to affect underground mines operating in CO2 rich coal seams, including the primary coal seam of the Company’s Metropolitan Mine. Importantly, a minimum three-year transition period applies for any change to standards. SWA expects to make recommendations to the Work Health and Safety and Health Act 1999 concerning, among other things, dutiesMinisters on the proposed workplace exposure standards in the first quarter of officers, reporting requirements for coal mine worker diseases, reporting defects and hazards affecting plant and substances, contractor and service provider safety and health management plans, new powers to suspend or cancel an individual’s statutory certificate2023.
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Industrial Relations. A national industrial relations system, the Fair Work Act and National Employment Standards, administered by the federal government applies to all employers and employees. The matters regulated under the national system include general employment conditions, unfair dismissal, enterprise bargaining, bullying claims, industrial action and resolution of workplace disputes. Most of the hourly workers employed in ourthe Company’s mines are also covered by the Black Coal Mining Industry Award and company specific enterprise agreements approved under the national system.
National Greenhouse and Energy Reporting Act 2007 (NGER Act). The NGER Act imposes requirements for corporations meeting a certain threshold to register and report greenhouse gas emissions and abatement actions, as well as energy production and consumption as part of a single, national reporting system. The Clean Energy Regulator administers the NGER Act. The federal Department of Environment and Energy is responsible for NGER Act-related policy developments and review.
On July 1, 2016, amendments to the NGER Act implemented the Emissions Reduction Fund Safeguard Mechanism. From that date, large designated facilities such as coal mines were issued with a baseline for their covered emissions and must take steps to keep their emissions at or below the baseline or face penalties.
The National Greenhouse and Energy Reporting (Safeguard Mechanism) Rule 2015 outlines key elements of a responsible emitter’s duty to avoid an excess emissions situation and provides detail on how it can meet that requirement. The rule was amended in Marchbetween 2019 withand 2021 to transition responsible emitters to new baseline setting arrangements. From the effect that all current reported covered emissionsstart of the 2020-21 compliance year, baselines will expire on June 30, 2020,must use prescribed production variables (an example being run of mine coal) and there will be alternatives for setting new baselines, including by reference to default emissions intensity values.values (being values set by the government to represent the industry average emissions intensity of production over five years) unless specific exemptions apply (such as a facility having site-specific values set).
On January 10, 2023, the Australian federal government released its Safeguard Mechanism Reforms Position Paper setting out the proposed changes to the emissions reduction regime. The reforms will commence on July 1, 2023 utilizing site specific baseline emissions as benchmarks for year-on-year improvement (proposed to be 4.9% each year to 2030) before transitioning to industry average emissions benchmarks by 2030. Proponents will earn tradeable credits (Safeguard Mechanism Credits) when emissions are below their baselines or can purchase credits to offset emissions. Access to existing Australian Carbon Credit Units will continue unchanged albeit with a price ceiling of $75 Australian dollars per tonne of CO2 in 2023-24, increasing with the Consumer Price Index plus 2% each year. After further consultation, the Australian government aims to finalize the legislative amendments to implement the Safeguard Mechanism reforms by April 2023. The potential impact of these reforms to Peabody’s Australian operations is under review.
Queensland Royalty. Royalties are payableAs part of the Queensland government’s 2019-20 budget, the government committed to freeze royalty rates on coal and minerals for three years, provided companies voluntarily contributed to a Resource Community Infrastructure Fund (the Fund) over this three-year period. The government contributed $30 million Australian dollars towards the Fund, with companies voluntarily contributing $70 million Australian dollars. Peabody’s contribution to the StateFund was approximately $457,000 Australian dollars for the 2021-22 financial year, $522,000 Australian dollars for the 2020-21 financial year and $713,000 Australian dollars for the 2019-20 financial year.
On and from July 1, 2022, the Queensland government introduced three new royalty tiers for coal produced and sold from the state. The new tier rates are 20% for the portion of Queensland at a rate of 12.5% on coal prices over $100above $175 Australian dollars per tonne and up to $150tonne; 30% for the portion of prices above $225 Australian dollars per tonnetonne; and 15.0% on pricing overa 40% tier for the portion of prices above $300 Australian dollars per tonne. Previously, the maximum royalty rate was 15% of the value of the coal sold above $150 Australian dollars per tonne. The rate is 7.0%change follows a three-year freeze on royalty rates for coal sold below $100in the state. Through December 31, 2022, the Company paid additional royalties of $69.9 million Australian dollars per tonne. The periodic impact of these royalty rates is dependent upon the volume of tonnes produced at each of our Queensland mining locations and coal prices received for those tonnes. The Queensland Office of State Revenue issues determinations setting out its interpretationas a result of the laws that impose royalties and provide guidance on how royalty rates should be calculated.new rates. The increased rate structure may impact the Company’s future decisions about its Queensland operations.
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New South Wales Royalty. In New South Wales, the royalty applicable to coal is charged as a percentage of the value of production (total revenue less allowable deductions). This is equal to 6.2% for deep underground mines (coal extracted at depths greater than 400 meters below ground surface), 7.2% for underground mines and 8.2% for open-cut mines.
Sydney Water Catchment Areas. In November 2017, the New South Wales government established an independent expert panel (Panel) to advise the Department of Planning Industry and Environment (DPIE)(DPE) on the impact of underground mining activities in Sydney’s water catchment areas, including at ourthe Company’s Metropolitan Mine. The Panel issued an initial report to DPIE in November 2018, which was publicly released in December 2018 and only concerned mining activities at two mines, our Metropolitan Mine and a competitor’s Dendrobium Mine. After consultation with stakeholders, including Peabody, aits final report was released in October 2019. The final report updates and finalizes the initial report and also makes2019, which made findings and recommendations concerning mining activities and effects across the catchment as a whole.
In response to the Panel’s recommendations, in 2020 the DPE established an interagency taskforce to implement a detailed action plan which includes: ensuring there is a net gain for the metropolitan water supply by requiring more offsetting from mining companies; establishing a new independent expert panel (Independent Advisory Panel) to advise on future mining applications in the catchment; strengthening surface and groundwater monitoring; improving access to and transparency of environmental data; adopting a more stringent approach to the assessment and conditioning of future mining proposals to minimize subsidence impacts; reviewing and updating current and potential future water losses from mining in line with the best available science; introducing a licensing regime to properly account for any water losses; and undertaking further research into mine closure planning to reduce potential long-term impacts.
When requested by the DPE, the Independent Advisory Panel is available to provide informed technical advice to the DPE or the Independent Planning Commission in relation to development applications and post-approval matters relating to the assessment and management of subsidence impacts associated with underground mining across NSW, with a particular focus on risks to the quantity of water in the catchment. The Panel’s reports acknowledgeIndependent Advisory Panel is comprised of an independent chair and experts in the major effort at the Metropolitanfields of mining engineering and Dendrobium Mines over the last decade to employ best practice modeling and assessment methods undertaken by suitable specialists, with expert peer review while recommending continued rigorous monitoring and impact assessment in order to build on the knowledge base regarding mining-induced subsidence, and its impacts onsurface water, groundwater and swamp hydrology and ecology. Advice that may be provided by the Independent Advisory Panel may include, but is not confined to, risks to the total water quantity and holding capacity of surface water.and groundwater systems, including swamps and reservoirs, and the types and reliability of methodologies used to predict, monitor, assess and report on mining effects, impacts and consequences.
Risks Related to Global Climate Change
Peabody recognizes that climate change is occurring and that human activity, including the use of fossil fuels, contributes to GHG emissions. The reports endorseCompany’s largest contribution to GHG emissions occurs indirectly, through the government taking an incremental approach to mining approvals that provides for considering existing and emerging information and knowledge gaps. The Panel concludedcoal used by its customers in the final report that the average daily water inflow over the last three years at the Metropolitan Mine is generally less than 0.2 megaliters per day and shows no evidencegeneration of connected fracture regime to surface or correlation with rainfall. It also concluded that the potential for water to be diverted out of Woronora Reservoir and into other catchments through valley closure shear planes and geological structures will require careful assessment in the future because it is planned that most of the remaining longwall panels in the approved mining area will pass beneath the reservoir. A range of matters remain to be considered by the Panel, including the cumulative impacts of flow losseselectricity and the relative significanceproduction of these for water suppliessteel (Scope 3). To a lesser extent, the Company directly and indirectly contributes to GHG emissions from various aspects of its mining operations, including from the use of electrical power and combustible fuels, as well as from the practicalitiesfugitive methane emissions associated with establishingcoal mines and stockpiles (Scopes 1 and 2).
Peabody’s board of directors and management believe that coal is essential to affordable, reliable energy and will continue to play a robust regional water balance model.significant role in the global energy mix for the foreseeable future. Peabody views technology as vital to advancing global climate change solutions, and the Company supports advanced coal technologies to drive continuous improvement toward the ultimate goal of net-zero emissions from coal.
The DPIE will now consider the recommendations in the Panel’s final reportboard of directors has ultimate oversight for climate-related risk and opportunity assessments, and has saiddelegated certain aspects of these assessments to subject matter committees of the board. In addition, the board and its committees are provided regular updates on major risks and changes, including climate-related matters. The senior management team champions the strategic objectives set forth by the board of directors and Peabody’s global workforce turns those objectives into meaningful actions.
Management believes that in the meantime no new development applications for mining inCompany’s external communications, including environmental regulatory filings and public notices, U.S. Securities and Exchange Commission filings, its annual Environmental, Social and Governance (ESG) Report, its website and various other stakeholder-focused publications provide a comprehensive picture of the catchment will be determined. We do not currently have anyCompany’s material risks and progress. All such applications awaiting determination. communications are subject to oversight and review protocols established by Peabody’s board of directors and executive leadership team.
The latest extraction plans forCompany faces risks from both the Metropolitan Mine are progressing on an incremental basisglobal transition to a net-zero emissions economy and we continue to conduct robust monitoring, data collectionthe potential physical impacts of climate change. Such risks may involve financial, policy, legal, technological, reputational and reportingother impacts as the Company meets various mitigation and have been actively consulting with the government on Metropolitan’s approval processes and mine design to ensure that operational impacts are appropriately managed and minimized as far as possible.
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•Reduced utilization or closure of existing coal-fired electricity generating plants;
•Electricity generators switching from coal to alternative fuels, when feasible;
•Increased costs associated with regulatory compliance;
•Unfavorable impact of regulatory compliance on supply and demand fundamentals, such as limitations on financing or construction of new coal-fueled power stations;
•Uncertainty and inconsistency in rulemaking processes related to periodic governmental administrative and policy changes;
•Unfavorable costs of capital and access to financial markets and products due to the policies of financial institutions;
•Disruption to operations or markets due to anti-coal activism and litigation; and
•Reputational damage associated with involvement in GHG emissions.
With respect to the potential or actual physical impacts of climate change, the Company has identified the following specific risks:
•Disruption to water supplies vital to mining operations;
•Disruption to transportation and other supply chain activities;
•Damage to the Company’s, customers’ or suppliers’ plant and equipment, or third-party infrastructure, resulting from weather events or changes in environmental trends and conditions; and
•Electrical grid failures and power outages.
While the Company faces numerous risks associated with the transition to a net-zero emissions economy and the physical impacts of climate change, certain opportunities may also emerge, such as:
•Heightened emphasis among multiple stakeholders to develop high-efficiency, low-emissions (HELE) technologies and CCUS technologies;
•Increased steel demand related to construction and other infrastructure projects related to climate change concerns; and
•The relative expense and reliability of renewable energy sources compared to coal may encourage support for balanced-source energy policies and regulations.
Global climate issues continue to attract public and scientific attention. Numerous reports, such as the Fourth and the Fifth Assessment Report of the Intergovernmental Panel on Climate Change, have also engendered concern about the impacts of human activity, especially fossil fuel combustion, on global climate issues. In turn, increasing government attention is being paid to global climate issues and to GHG emissions, including emissions of carbon dioxide from coal combustion by power plants. There have been significant developments in federal and state legislation and regulation and international accords regarding climate change. Such developments are described below in the section “Regulations Related to Global Climate Change” within this Item 1.
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. The Company believes HELE and CCUS technologies should be part of the solution to achieve substantial reductions in GHG emissions and should be broadly supported and encouraged, including through eligibility for public funding from national and international sources. In addition, CCUS merits targeted deployment incentives, like those provided to other low-emission sources of energy.
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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.
Regulations Related to Global Climate Change
In the U.S., Congress has considered legislation addressing global climate issues and greenhouse gasGHG emissions, but to date, no suchnew comprehensive, regulatory legislation has been signed into law. The U.S. Congress, however, has approved legislation, the Inflation Reduction Act of 2022, that will provide substantial tax incentives, grants and loan guarantees for energy infrastructure, solar panels, wind turbines, nuclear and geothermal energy, hydrogen projects and carbon capture and storage. While it is possible that the U.S. will adopt additional climate legislation in the future, the timing and specific requirements of any such legislation are uncertain. In the absence of new U.S. federal legislation, the
The EPA is undertakinghas also undertaken several steps to regulate greenhouse gasGHG emissions pursuant tounder existing law, primarily the CAA. In response to the 2007 U.S. Supreme Court ruling in Massachusetts v. EPA, the EPA commenced several rulemaking projects as described under “Regulatory Matters - U.S.” In particular, in 2015, the EPA announced final rules (known as the CPP) for regulating carbon dioxide emissions from existing and new fossil fuel-fired EGUs. Twenty-seven states and governmental entities, as well as utilities, industry groups, trade associations, coal companies (including Peabody), and other entities, challenged the CPP in federal court. Implementation of the CPP was stayed by the U.S. Supreme Court pending resolution of its legal challenges. In October 2017, the EPA proposed to change its legal interpretation of section 111(d) of the CAA, the authority that the agency relied on for the original CPP. The EPA relied on the proposed reinterpretation until August 2018, when it proposed the Affordable Clean Energy Rule (the ACE Rule) to replace the CPP with a system where states would develop emissions reduction plans using BSER measures (essentially efficiency heat rate improvements), and the EPA would approve the state plans if they use EPA-approved candidate technologies. Changes in the NSR program were also proposed to allow efficiency improvements to be made without triggering NSR requirements. In September 2019, the ACE Rule, which provides states with the flexibility to regulate on a plant-by-plant basis with a focus on coal-fired EGUs, became effective and the CPP was repealed. Proposed revisions to the regulations under the NSR program that were part of the ACE proposal were separated and the EPAhas indicated that it intends to take final action on the proposed NSR program reforms at a later date. Following the effectiveness of the ACE Rule, the case challenging the CPP in federal court was dismissed as being moot. The ACE Rule is being challenged in the D.C. Circuit Court of Appealswill continue these efforts and its ultimate impact will depend on state implementation plan requirementsproceed with new regulations affecting GHG emissions from fossil fuel-fired electric generation, methane emissions from oil and the outcome of associated legal challenges.gas production and carbon emissions from light and heavy-duty vehicles.
At the same time, a number of states in the U.S. have adopted programs to regulate greenhouse gasGHG emissions. For example, 10 northeastern states (Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Rhode Island and Vermont) entered into the Regional Greenhouse Gas Initiative (RGGI) in 2005, whichand Pennsylvania joined in 2022. RGGI is a mandatory cap-and-trade program to cap regional carbon dioxide emissions from power plants. In 2011, New Jersey announced its withdrawal from RGGI effective January 1, 2012. Six mid-western states (Illinois, Iowa, Kansas, Michigan, Minnesota and Wisconsin) and one Canadian province have entered into the Midwestern Regional Greenhouse Gas Reduction Accord (MGGRA) to establish voluntary regional greenhouse gas reduction targets and develop a voluntary multi-sector cap-and-trade system to help meet the targets. It has been reported that, while the MGGRA has not been formally suspended, the participating states are no longer pursuing it. Seven western states (Arizona, California, Montana, New Mexico, Oregon, Utah and Washington) and four Canadian provinces entered into the Western Climate Initiative (WCI) in 2008 to establish a voluntary regional greenhouse gas reduction goal and develop market-based strategies to achieve emissions reductions. However, in November 2011, the WCI announced that six states had withdrawn from the WCI, leaving California and four Canadian provinces as the remaining members. Of those five jurisdictions, only California and Quebec have adopted greenhouse gas cap-and-trade regulations to date and both programs have begun operating. Many of the states and provinces that left WCI, RGGI and MGGRA, along with many that continue to participate, have joined the new North America 2050 initiative, which seeks to reduce greenhouse gasGHG emissions and create economic opportunities in ways not limited to cap-and-trade programs.
Several other U.S. states have enacted legislation establishing greenhouse gasGHG emissions reduction goals or requirements. In addition, several states have enacted legislation or have in effect regulations requiring electricity suppliers to use renewable energy sources to generate a certain percentage of power or that provide financial incentives to electricity suppliers for using renewable energy sources. Some states have initiated public utility proceedings that may establish values for carbon emissions.
Peabody participated in the Department of Energy’s Voluntary Reporting of Greenhouse Gases Program until its suspension in May 2011, and wethe Company regularly disclosediscloses information regarding its production-related emissions in ourits annual Environmental, Social and Governance Report the quantity of emissions per ton of coal produced by us in the U.S.ESG Report. The vast majority of ourthe Company’s emissions are generated by the operation of heavy machinery to extract and transport material at ourits mines and fugitive emissions from the extraction of coal.
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The Kyoto Protocol, adopted in December 1997 by the signatories to the 1992 United Nations Framework Convention on Climate Change (UNFCCC), established a binding set of greenhouse gasGHG emission targets for developed nations. The U.S. signed the Kyoto Protocol but it has never been ratified by the U.S. Senate. Australia ratified the Kyoto Protocol in December 2007 and became a full member in March 2008. There were discussions to develop a treaty to replace the Kyoto Protocol after the expiration of its commitment period in 2012, including at the UNFCCC conferences in Cancun (2010), Durban (2011), Doha (2012) and Paris (2015). At the Durban conference, an ad hoc working group was established to develop a protocol, another legal instrument or an agreed outcome with legal force under the UNFCCC, applicable to all parties. At the Doha meeting, an amendment to the Kyoto Protocol was adopted, which included new commitments for certain parties in a second commitment period, from 2013 to 2020. In December 2012, Australia signed on to the second commitment period. During the UNFCCC conference in Paris, France in late 2015, an agreement was adopted calling for voluntary emissions reductions contributions after the second commitment period ends in 2020 (the Paris Agreement). The agreement was entered into force on November 4, 2016 after ratification and execution by more than 55 countries, including Australia, that account for at least 55% of global greenhouse gasGHG emissions. TheOn January 20, 2021, the U.S. has begun the process of withdrawing fromreentered the Paris Agreement which cannot be completed until 2020 underby accepting the termsagreement and all of its articles and clauses, after having announced its withdrawal from the agreement.agreement in November 2019.
In October 2017,June 2022, the new Australian Federal Government releasedfederal government announced plans to legislate for a plan aimed at delivering an affordable43% reduction in Australia’s GHG emissions by 2030 and reliable energy systemto introduce changes by mid-2023 that meets Australia’s international commitmentswill require heavy emitting companies producing more than 100,000 tonnes of carbon emissions annually to accelerate their emissions reduction. The plan was referred to as the National Energy Guarantee (NEG) and was aimed at changing the National Electricity Market and associated legislative framework. The NEG was abandoned byreduction activities. On September 13, 2022, the Australian government in September 2018. Followingpassed the outcomeClimate Change Act 2022 to set the GHG emissions reduction targets into law.
On January 10, 2023, the Australian federal government released its Safeguard Mechanism Reforms Position Paper setting out the proposed changes to the emissions reduction regime (legislated through the National Greenhouse and Energy Reporting Act 2007 (Cth)). Refer to the section “Regulatory Matters —Australia” within this Item 1 for discussion of the federal election in May 2019, the federal government confirmed it will not revive the former NEG policy. Instead, the government will pursue a new energy and climate change policy, which includes a $2 billion Australian dollars investment in projects to bring down Australia's greenhouse gas emissions. The Climate Solutions Fund is an extension of the former Emissions Reduction Fund. The government has confirmed that it remains committed to meeting Australia’s Paris Agreement targets but that the focus of energy policy will be on driving down electricity prices.proposed reform.
Available Information
In addition, copies of ourthe Company’s filings will be made available, free of charge, upon request by telephone at (314) 342-7900 or by mail at: Peabody Energy Corporation, Peabody Plaza, 701 Market Street, St. Louis, Missouri 63101-1826, attention: Investor Relations.
Item 1A. Risk Factors.
Risks Associated with Our Emergence from the Chapter 11 Cases
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Coal prices are dependent upon factors beyond ourthe 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 ourthe Company’s coal sales by volume during 20192022 and 2018. The2021, with the vast majority of ourthese sales of thermal coal were to electric power generators. The demand for coal consumed for electric power generation is affected by many of the factors described above, but primarily by (i) the overall demand for electricity; (ii) the availability, quality and price of competing fuels, such as natural gas, nuclear, fuel oil and alternative energy sources; (iii) utilization of all electricity generating units (whether using coal or not), including the relative cost of producing electricity from multiple fuels, including coal; (iv) stringent environmental and other governmental regulations; (v) other sociopolitical views on coal; and (v)(vi) the coal inventories of utilities. Gas-fueled generation has displaced and is expected tocould 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 are making uneconomichave 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. TheseIn recent years, these trends have reduced demand for ourthe Company’s coal and the related prices. Any further reduction in the amount ofLower demand for coal consumed by electric power generators could reduce the volume and price of thermal coal that we minethe Company sells and sell.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 balance between coal demand and supply, factoring in demand and supply of closely related and competing segments such as natural gas,fuel sources, both domestically and internationally, could materially reduce coal prices and therefore materially reduce our revenuesthe Company’s revenue and profitability. In the U.S., we competeThe Company competes with other fuel sources used for electricity generation, such as natural gas, nuclear and renewables. OurThe Company’s seaborne products compete with other producers as well as other fuel sources. Declines in the price of natural gas or continued low natural gas prices, 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 United States,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 ourthe Company’s coal, thereby reducing our revenuesits revenue and materially and adversely affecting ourits business and results of operations.
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If a substantial number of ourthe 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, our revenuesits revenue and operating profits could suffer if we arethe Company is unable to find alternate buyers willing to purchase ourits coal on comparable terms to those in ourits contracts.
Most of ourthe Company’s sales are made under coal supply agreements, which are important to the stability and profitability of ourits operations. The execution of a satisfactory coal supply agreement is frequently the basis on which we undertakethe 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 ourthe Company’s coal supply agreements contain provisions that permit the parties to adjust the contract price upward or downward at specified times. WeThe 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. WeThe Company may experience reductions in coal prices in new long-term coal supply agreements replacing some of ourits expiring contracts. Coal supply agreements also typically contain force majeure provisions allowing temporary suspension of performance by usthe 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 wethe Company amend the agreements to allow for such variation. Most of ourits coal supply agreements contain provisions requiring usthe 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 ourthe Company’s customers to terminate their contracts in the event of changes in regulations affecting ourthe 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.
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 numbersubstantial portion of these customers significantly reduce their purchases ofthe Company’s coal from us,supply agreements were modified or if we areterminated, it could be materially adversely affected to the extent that it is unable to sellfind 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 them on terms as favorable to us asreplace existing long-term coal supply agreements at the terms under our current agreements, our financial condition and results of operations could suffer materially.same prices or with similar profit margins when they expire. In addition, ourthe 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.
| Successor | Predecessor | |||||||||||||
| Year Ended December 31, 2019 | Year Ended December 31, 2018 | April 2 through December 31, 2017 | January 1 through April 1, 2017 | |||||||||||
| (Dollars and tons in millions) | ||||||||||||||
| Adjusted EBITDA | $ | 170 | $ | 110 | $ | 77 | $ | 27 | ||||||
| Depreciation, depletion and amortization and asset retirement obligation expense | $ | 111 | $ | 120 | $ | 60 | $ | 19 | ||||||
| Tons of coal sold | 4.0 | 6.6 | 4.8 | 1.5 | ||||||||||
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Risks inherent to mining could increase the cost of operating ourthe Company’s business, and events and conditions that could occur during the course of ourits mining operations could have a material adverse impact on us.the Company.
•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 ourits longwall equipment;
•unexpected maintenance problems; and
•unforeseen delays in implementation of mining technologies that are new to ourits operations.
The value of ourthe Company’s assets have from time to time been adversely affected by numerous uncertain factors, some of which are beyond ourits control, including unfavorable changes in the economic environments in which we operate,it operates; declining coal-fired electricity generation; lower-than-expected coal pricing,pricing; technical and geological operating difficulties,difficulties; an inability to economically extract ourits coal reserves and resources; and unanticipated increases in operating costs. During the year ended December 31, 2019, the Company recorded $270.2 million of impairment charges related to such factors, as further described in Note 5. “Asset Impairment” to the accompanying consolidated financial statements. These factors may trigger the recognition of additional impairment charges in the future, which could have a substantial impact on ourthe Company’s results of operations.
Because of the volatile and cyclical nature of U.S. and international coal markets, it is reasonably possible that ourthe Company’s current estimates of projected future cash flows from ourits mining assets may change in the near term, which may result in the need for adjustments to the carrying value of ourits assets.
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The Company could be negatively affected if we failit fails to maintain satisfactory labor relations.
As of December 31, 2019, we2022, the Company had approximately 6,6005,500 employees (excluding employees that were employed at operations classified as discontinued), which included approximately 5,0004,300 hourly employees. We areThe Company is party to labor agreements with various labor unions that represent certain of ourits employees. Such labor agreements are negotiated periodically, and, therefore, we arethe Company is subject to the risk that these agreements may not be able to be renewed on reasonably satisfactory terms. Approximately 42%34% of ourits hourly employees were represented by organized labor unions and generated approximately 19%16% of ourits coal production for the year ended December 31, 2019.2022. Relations with ourits employees and, where applicable, organized labor are important to ourthe Company’s success. If some or all of ourits current non-union operations were to become unionized, wethe Company could incur an increased risk of work stoppages, reduced productivity and higher labor costs. Also, if we failthe Company fails to maintain good relations or successfully negotiate contracts with ourits employees who are represented by unions, wethe Company could potentially experience labor disputes, strikes, work stoppages, slowdowns or other disruptions in production that could negatively impact ourits profitability.
U.S. federal and state laws and Australian laws require usthe Company to provide financial assurances related to requirements to reclaim lands used for mining,mining; to pay federal and state workers’ compensation, such as black lung liabilities; to provide financial assurances for coal lease obligationsobligations; and to satisfy other miscellaneous obligations. The primary methods we usethe Company uses to meet those obligations are to provide a third-party surety bond or provide a letter of credit. As of December 31, 2019, we2022, the Company had $1,609.2$1,376.8 million of outstanding surety bonds and $200.5$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.guarantees, in addition to collateral for sureties.
•lack of availability, higher expense or unfavorable market terms of new surety bonds, bank guarantees or letters of credit; and
•inability to provide or fund collateral for current and future third-party issuers of surety bonds, bank guarantees or letters of credit.credit; and
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 ourits mining permits and prevent mining operations from continuing, which would cast substantial doubt on our abilitycould result in its inability to continue as a going concern.
| Peabody Energy Corporation | 2022 Form 10-K | 31 | ||||||
The Company’s mining operations are extensively regulated, which imposes significant costs on us,it, and future regulations and developments could increase those costs or limit ourits 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 ourthe Company’s mines, ourits production and sale of coal would be disrupted and weit may be required to incur cash outlays to re-open the mine. Any of these actions could have a material adverse effect on ourthe Company’s financial condition, results of operations and cash flows.
For additional information about the various regulations affecting us,the Company, see the sections entitled “Regulatory Matters —U.S.” and “Regulatory Matters — Australia”.Australia.”
| Peabody Energy Corporation | ||||||||
Numerous governmental and tribal permits and approvals are required for mining operations. The permitting rules, and the interpretations of these rules, are complex, change frequently and are often subject to discretionary interpretations by regulators, all of which may make compliance more difficult or impractical. As part of this permitting process, when we applythe Company applies for permits and approvals, we areit 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 ourthe 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 ourthe Company’s ability to efficiently and economically conduct ourits mining activities, any of which would materially reduce ourits production, cash flows and profitability.
Concerns about the impacts of coal combustion on global climate are increasingly leading to consequencesconditions that have affected and could continue to affect demand for ourthe Company’s products or ourits securities and ourits ability to produce, including increased governmental regulation of coal combustion and unfavorable investment decisions by electricity generators.
Global climate issues continue to attract public and scientific attention. Numerous reports, such asincluding 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 mines or coal-fueled power stations could adversely impact the global supply and demand for coal.coal in the future. The potential financial impact on usPeabody of such future laws, regulations or other policies will depend upon the degree to which any such laws or regulations force electricity generators to diminish their reliance on coal as a fuel source. That, in turn, will depend on a number of factors, including the specific requirements imposed by any such laws, regulations or other policies, the time periods over which those laws, regulations or other policies would be phased in, the state of development and deployment of CCUS technologies as well as acceptance of CCUS technologies to meet regulations and the alternative uses for coal. Similarly, higher-efficiencyHigher-efficiency coal-fired power plants may also be an option for meeting laws or regulations related to emissions from coal use. Several countries, including some major coal users such as China, India and Japan, included using higher-efficiency coal-fueled power plants in their plans under the Paris Agreement.
From time to time, wethe 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 that we make significant assumptions as to the specific provisions of such potential laws, regulations and policies which sometimes show that if implemented in the manner assumed by the analyses, the potential laws, regulations and policies could result in material adverse impacts on ourthe Company’s operations, financial condition or cash flows. We do not believe that suchSuch analyses cannot be relied upon to reasonably predict the quantitative impact that future laws, regulations or other policies may have on ourthe Company’s results of operations, financial condition or cash flows.
| Peabody Energy Corporation | ||||||||
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 ourthe 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 been to makemade it more costly and difficult to maintain ourthe Company’s business. These cost increases and/or a substantial or extended declinedeclines in the prices we receivethe Company receives for ourits coal due to these or other factors could reduce ourits revenue and profitability, cash flows, liquidity, and value of ourits coal reserves and resources, and could result in material losses.
The degreeCompany’s trading and hedging activities do not cover certain risks and may expose it to which we are leveraged could have important consequences, including, but not limited to:
In addition our indebtedness subjects us 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 restrictive covenants. Failurehedging 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 useach 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 comply withreclaim the disturbed acreage and the timing of these covenantscash 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 result in an event of default that,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 not cured or waived,actual amounts change significantly from its assumptions, which could have a material adverse effect on usits 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.
| Peabody Energy Corporation | 2022 Form 10-K | 34 | ||||||
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 amounts outstanding thereundersignificant 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 immediately duematerially 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 payable.resources, the Company must also own the rights to the related surface property and receive various governmental permits. The termsCompany 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 our indebtedness provideits 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 we cannot meet our debt service obligations,available, may not be available on satisfactory terms. If the lenders could foreclose against the assets securing their borrowingsCompany is unable to fund these activities, it may not be able to maintain or increase its existing production rates and we could be forced into bankruptcy or liquidation.to change its business strategy, which could have a material adverse effect on its financial condition, results of operations and cash flows.
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 matters, additionalthings, 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 financial assurancespermits;
•employee health and safety; and
•historical production from the area compared with production from other producing areas.
| Peabody Energy Corporation | 2022 Form 10-K | 35 | ||||||
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 our reclamation bonding requirements, a requirement to post additional collateral on derivative trading instruments that we may enter into, the lossits 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 trading counterparties for corporate hedgingoperations, financial position and trading and brokerage activitiescash flows.
Joint ventures, partnerships or an increase in the cost of, or a limit on our access to, various forms of credit used in operating our business.
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, meet our scheduled debtthe 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. Our indebtednessIts 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 restrictbe 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 usecost 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 proceeds from any such sales. We may not be able to complete those salesstructure of its contracts and the proceedscontract bidding process as well as the competitive industries, economic conditions and countries in which the Company operates. Accordingly, substantial inflation may not be adequate to meet any debt service obligations then due.result in a material adverse impact on the Company’s costs, profitability and financial results.
| Peabody Energy Corporation | 36 | |||||||
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.
| Peabody Energy Corporation | 2022 Form 10-K | 37 | ||||||
•global economic recessions and/or credit market disruptions;
•deterioration of the creditworthiness of its customers or counterparties to incur substantially more debt,financial instruments, and their ability to perform under contracts;
•inability of suppliers and other counterparties, including secured debt, which could further increasethose related to transportation, contract mining, service provision, and coal trading and brokerage, to fulfil the risksterms 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 our indebtedness.the Company’s global operating platform, including country and political risks, international regulatory requirements, and foreign currency rates.
The terms of our indenture governing our senior secured notes and the agreements and instruments governing our other indebtednessthe Company’s debt and surety bonding obligations impose restrictions that may limit ourits operating and financial flexibility.
The indenture governing our senior secured notes and the agreements governing our other indebtednessthe Company’s debt and surety bonding obligations contain certain restrictions and covenants which restrict ourits 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 ourthe Company’s ability to operate ourits business, as well as significantly affect ourits liquidity, and therefore could adversely affect ourits results of operations. Our credit facility also contains a mandatory prepayment provision providing that certain amounts of excess cash flow (as defined in the agreements governing the facility) must be utilized to make payments on the outstanding balance under that facility.
These restrictions and covenants limit, among other things, ourthe 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 ourits assets; and
| Peabody Energy Corporation | 2022 Form 10-K | 38 | ||||||
The number and quantity of viable financing and insurance alternatives available to usthe 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 ourits efforts with respect to environmental and social matters and related governance considerations could harm the perception of our companythe Company by certaina significant number of investors or result in the exclusion of ourits 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, which alsocoal. 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 corporateenvironmental, social and governance related to environmental and social 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 ourthe Company’s ability to access capital and financial markets in the future;
•reducing the demand and price for ourits equity securities;
•increasing the cost of borrowing;
•causing a decline in ourthe Company’s credit ratings;
•reducing the availability, and/or increasing the cost of, third-party insurance;
•increasing ourthe 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 ourthe Company’s flexibility in business development activities such as mergers, acquisitions and divestures.divestitures.
Risks Related to Ownership of OurPeabody’s Securities
The price of ourPeabody’s securities may be volatile.
The price of ourPeabody’s common stock (Common Stock) may fluctuate due to a variety of market and industry factors that may materially reduce the market price of ourits Common Stock regardless of ourits operating performance, including, among others:
•actual or anticipated fluctuations in ourPeabody’s quarterly and annual results and those of other public companies in ourits 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 usPeabody or to accurately predict the results weit actually achieve;achieves;
•changes in accounting principles;
•announcements concerning usPeabody or ourits competitors;
•the purchase and sale of shares of its Common Stock by significant shareholders;
•lack of or excess of trading liquidity; and
•the general statevolatility of the securities market.markets.
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Peabody’s Common Stock is subject to dilution and may be subject to further dilution in the future.
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 ourthe Company’s other stakeholders. A significant stockholder may exert substantial influence over usthe Company to cause usthe 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 usPeabody 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 usPeabody or other holders of ourits Common Stock or debt instruments.
The Company’s ability to use its net operating lossU.S. NOL carryforwards may be limited if it experiences an “ownership change” as defined in Section 382 (Section 382) of the Internal Revenue Code of 1986, as amended. An ownership change generally occurs if certain stockholders increase their aggregate percentage ownership of a corporation’s stock by more than 50 percentage points over their lowest percentage ownership at any time during the testing period, which is generally the three-year period preceding any potential ownership change.
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Acquisitions and divestitures are a potentially important part of ourthe Company’s long-term strategy, subject to ourits investment criteria, and involve a number of risks, any of which could cause usthe Company not to realize the anticipated benefits.
Provisions contained in ourPeabody’s certificate of incorporation and by-laws and Delaware law could make it more difficult for a third-party to acquire us,it, even if doing so might be beneficial to ourits stockholders. Provisions of ourPeabody’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 ourits 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 ourthe Company’s reported financial results.
The mining industry has limited industry-specific accounting literature and, as a result, we understandthe 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, wethe Company may need to restate ourits reported results if the resulting interpretations differ from ourits current accounting practices. Refer to Note 1. “Summary of Significant Accounting Policies” to the accompanying consolidated financial statements for a summary of ourthe Company’s significant accounting policies.
Item 1B. Unresolved Staff Comments.
None.
Item 2. Properties.
Coal Reserves and Resources
Proven and Probable Reserves as of December 31, 2019 (1) | |||||||||||
Owned Tons | Leased Tons | Total Tons | |||||||||
| Mining Segment | Locations | ||||||||||
| (Tons in millions) | |||||||||||
| Seaborne Thermal Mining | New South Wales | — | 250 | 250 | |||||||
| Seaborne Metallurgical Mining | Queensland, New South Wales and Alabama | — | 297 | 297 | |||||||
| Powder River Basin Mining | Wyoming | — | 2,309 | 2,309 | |||||||
| Midwestern U.S. Mining | Illinois, Indiana and Kentucky | 927 | 228 | 1,155 | |||||||
| Western U.S. Mining | Arizona, New Mexico and Colorado | 32 | 7 | 39 | |||||||
| Total Proven and Probable Coal Reserves | 959 | 3,091 | 4,050 | ||||||||
| Total United States | 959 | 2,597 | 3,556 | ||||||||
| Total Australia | — | 494 | 494 | ||||||||
| Total Proven and Probable Coal Reserves | 959 | 3,091 | 4,050 | ||||||||
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 depositresource, which couldincludes 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 and legally extracted or produced at the timeviable project. The conversion of the reserve determination. Proven and probable coalreported mineral resources to mineral reserves are defined by SEC Industry Guide 7 as follows:
| Peabody Energy Corporation | ||||||||
Mineral resource classifications are then input into our computerized land management system, which overlays thatdifferentiated 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 dataconfidence; quantity and grade or quality are estimated on the basis of conclusive geological evidence and sampling. The level of geological certainty associated with data on ownership or controla 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 surface interestsinferred 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 extentgeologic confidence based on historical experience with a specific coal deposit. Resources are further evaluated using a set of our attributable coal reserves in a given area. Our land management system contains reserve information, including the quantitystructure and quality (where available)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 reserves,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 well as production data,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 ownership, lease paymentsresource is considered a proven coal reserve and other information relating to ourhas 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 land holdings. We periodically update our coal reserve estimates to reflect productionhave a moderate degree of coal from those reserves and new drilling or other data received. Accordingly, our coal reserve estimates will change from time to time to reflect the effects of our mining activities, analysis of new engineering and geological data, changes in coal reserve holdings, modification of mining methods and other factors.
For each mine or future mine, wethe Company develops Life-of-Mine (LOM) plans which employ a market-driven, risk adjustedrisk-adjusted capital allocation process to guide long-term mine planning of active operations and development projectsprojects. QPs rely on LOM planning as an integral process for economically mineable coal. We refer to this process as Life-of-Mine (LOM) planning.coal reserve and resource estimates. The LOM plan projects,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.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 recoverableviable coal in the LOM plan.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.
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.
| Peabody Energy Corporation | ||||||||
The pricing information usedCompany is party to establish our reserves includes internal, proprietary price forecasts and existing contract economics, in each case on a mine-by-mine and product-by-product basis. In general, our price forecasts are based on a thorough analytical process utilizing detailed supply and demand models, global economic indicators, projected foreign exchange rates, analyses of price relationships among various commodities, competing fuels analyses, projected steel demand, analyses of supplier costs and other variables. Price forecasts, supply and demand models and other key assumptions and analyses are stress tested against independent third-party research not commissioned by us to confirm the conclusions reached through our analytical processes, and our price forecasts fall within the ranges of the projections included in this third-party research. The development of the analyses, price forecasts, supply and demand models and related assumptions are subject to multiple levels of management review.
Private U.S. coal leases normally have terms of between 10 and 20 years and usually give usthe 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 our 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 reservescoal properties may expire or these leases may be renewed periodically.
Mining and exploration in Australia isare 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.
The pricing information used in support of the lessors or grantorsCompany’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 boundariescost of our leased properties are not completely verified until we prepare to mine those reserves.new supply (greenfield developments or extensions at existing mines).
| Peabody Energy Corporation | ||||||||
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 assignedcontractually passed on to our active operating mines, our property interestcustomers in those reserves and other characteristics of the facilities.
| SUMMARY OF COAL PRODUCTION AND SULFUR CONTENT OF ASSIGNED RESERVES | |||||||||||||||||||||||
| (Tons in millions) | |||||||||||||||||||||||
Sulfur Content of Assigned Reserves as of December 31, 2019 (1) | |||||||||||||||||||||||
| <1.2 lbs. | >1.2 to 2.5 lbs. | >2.5 lbs. | As | ||||||||||||||||||||
| Production | Sulfur | Sulfur | Sulfur | Received | |||||||||||||||||||
| Year Ended December 31, | Type of | Dioxide per | Dioxide per | Dioxide per | Btu per | ||||||||||||||||||
| Segment/Mining Complex | 2019 | 2018 | 2017 | Coal | Million Btu | Million Btu | Million Btu | pound (2) | |||||||||||||||
| Seaborne Thermal Mining: | |||||||||||||||||||||||
| Wilpinjong | 14.1 | 14.1 | 13.4 | T | 104 | — | — | 10,000 | |||||||||||||||
Wambo (3) | 5.6 | 5.2 | 5.9 | T/C | 146 | — | — | 11,300 | |||||||||||||||
| Total | 19.7 | 19.3 | 19.3 | 250 | — | — | |||||||||||||||||
| Seaborne Metallurgical Mining: | |||||||||||||||||||||||
| Coppabella | 2.4 | 2.7 | 2.8 | P | 24 | — | — | 12,600 | |||||||||||||||
| Shoal Creek | 1.9 | 0.2 | — | C | 53 | — | — | 12,700 | |||||||||||||||
| Moorvale | 1.7 | 2.1 | 1.8 | C/P/T | 8 | — | — | 12,500 | |||||||||||||||
| Metropolitan | 1.5 | 1.7 | 1.0 | C/P/T | 18 | — | — | 12,600 | |||||||||||||||
| Millennium | 0.6 | 1.9 | 3.3 | C/P | — | — | — | 12,600 | |||||||||||||||
| North Goonyella | — | 1.4 | 3.4 | C | 82 | — | — | 12,700 | |||||||||||||||
Middlemount (4) | — | — | — | C/P | 22 | — | — | 12,400 | |||||||||||||||
| Total | 8.1 | 10.0 | 12.3 | 207 | — | — | |||||||||||||||||
| Powder River Basin Mining: | |||||||||||||||||||||||
| North Antelope Rochelle | 85.3 | 98.3 | 101.6 | T | 1,610 | — | — | 8,800 | |||||||||||||||
| Caballo | 12.6 | 11.3 | 11.1 | T | 447 | 6 | — | 8,400 | |||||||||||||||
| Rawhide | 10.1 | 9.5 | 10.4 | T | 200 | 46 | — | 8,300 | |||||||||||||||
| Total | 108.0 | 119.1 | 123.1 | 2,257 | 52 | — | |||||||||||||||||
| Midwestern U.S. Mining: | |||||||||||||||||||||||
| Bear Run | 6.8 | 6.9 | 7.3 | T | 4 | 25 | 205 | 10,900 | |||||||||||||||
| Gateway North | 3.0 | 3.1 | 2.5 | T | — | — | 52 | 10,900 | |||||||||||||||
| Wild Boar | 2.5 | 2.7 | 2.7 | T | — | — | 30 | 11,100 | |||||||||||||||
| Francisco Underground | 2.0 | 2.2 | 2.2 | T | — | — | 14 | 11,370 | |||||||||||||||
Wildcat Hills Underground (5) | 1.4 | 1.3 | 1.5 | T | — | — | — | 12,100 | |||||||||||||||
| Somerville Central | 1.2 | 2.0 | 2.2 | T | — | — | 3 | 11,000 | |||||||||||||||
Cottage Grove (6) | 0.1 | 0.4 | 0.3 | T | — | — | — | — | |||||||||||||||
| Total | 17.0 | 18.6 | 18.7 | 4 | 25 | 304 | |||||||||||||||||
| Western U.S. Mining: | |||||||||||||||||||||||
| El Segundo/Lee Ranch | 5.5 | 5.5 | 4.9 | T | 4 | 23 | 7 | 9,100 | |||||||||||||||
Kayenta (7) | 3.8 | 6.5 | 6.2 | T | — | — | — | 10,600 | |||||||||||||||
| Twentymile | 2.6 | 3.1 | 3.8 | T | 5 | — | — | 11,200 | |||||||||||||||
| Total | 11.9 | 15.1 | 14.9 | 9 | 23 | 7 | |||||||||||||||||
| Total Assigned | 164.7 | 182.1 | 188.3 | 2,727 | 100 | 311 | |||||||||||||||||
| Peabody Energy Corporation | ||||||||
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:
ASSIGNED RESERVES (8) | ||||||||||||||||||||||||||||||||||||||
| AS OF DECEMBER 31, 2019 | ||||||||||||||||||||||||||||||||||||||
| (Tons in millions) | ||||||||||||||||||||||||||||||||||||||
| Attributable Ownership | 100% Project Basis | Modifying Factors (9) | ||||||||||||||||||||||||||||||||||||
| Proven and Probable Reserves | Proven and Probable Reserves | |||||||||||||||||||||||||||||||||||||
| Segment/Mining Complex | Interest | Owned | Leased | Surface | Underground | Owned | Leased | Surface | Underground | ROM Factor | Yield | |||||||||||||||||||||||||||
| Seaborne Thermal Mining: | ||||||||||||||||||||||||||||||||||||||
| Wilpinjong | 100% | 104 | — | 104 | 104 | — | 104 | — | 104 | 104 | — | 104 | % | 90 | % | |||||||||||||||||||||||
Wambo (3) | (a) | 146 | — | 146 | 36 | 110 | 179 | — | 179 | 69 | 110 | 99 | % | 73 | % | |||||||||||||||||||||||
| Total | 250 | — | 250 | 140 | 110 | |||||||||||||||||||||||||||||||||
| Seaborne Metallurgical Mining: | ||||||||||||||||||||||||||||||||||||||
| Coppabella | 73.3% | 24 | — | 24 | 24 | — | 33 | — | 33 | 33 | — | 93 | % | 77 | % | |||||||||||||||||||||||
| Shoal Creek | 100% | 53 | — | 53 | — | 53 | 53 | — | 53 | — | 53 | 102 | % | 56 | % | |||||||||||||||||||||||
| Moorvale | 73.3% | 8 | — | 8 | 8 | — | 11 | — | 11 | 11 | — | 117 | % | 80 | % | |||||||||||||||||||||||
| Metropolitan | 100% | 18 | — | 18 | — | 18 | 18 | — | 18 | — | 18 | 117 | % | 78 | % | |||||||||||||||||||||||
| Millennium | 100% | — | — | — | — | — | — | — | — | — | — | 95 | % | 79 | % | |||||||||||||||||||||||
| North Goonyella | 100% | 82 | — | 82 | — | 82 | 82 | — | 82 | — | 82 | 76 | % | 82 | % | |||||||||||||||||||||||
Middlemount (4) | 50% | 22 | — | 22 | 22 | — | 44 | — | 44 | 44 | — | 85 | % | 77 | % | |||||||||||||||||||||||
| Total | 207 | — | 207 | 54 | 153 | |||||||||||||||||||||||||||||||||
| Powder River Basin Mining: | ||||||||||||||||||||||||||||||||||||||
| North Antelope Rochelle | 100% | 1,610 | — | 1,610 | 1,610 | — | 1,610 | — | 1,610 | 1,610 | — | 92 | % | 100 | % | |||||||||||||||||||||||
| Caballo | 100% | 453 | — | 453 | 453 | — | 453 | — | 453 | 453 | — | 90 | % | 100 | % | |||||||||||||||||||||||
| Rawhide | 100% | 246 | — | 246 | 246 | — | 246 | — | 246 | 246 | — | 93 | % | 100 | % | |||||||||||||||||||||||
| Total | 2,309 | — | 2,309 | 2,309 | — | |||||||||||||||||||||||||||||||||
| Midwestern U.S. Mining: | ||||||||||||||||||||||||||||||||||||||
| Bear Run | 100% | 234 | 104 | 130 | 234 | — | 234 | 104 | 130 | 234 | — | 106 | % | 73 | % | |||||||||||||||||||||||
| Gateway North | 100% | 52 | 51 | 1 | — | 52 | 52 | 51 | 1 | — | 52 | 70 | % | 62 | % | |||||||||||||||||||||||
| Wild Boar | 100% | 30 | 11 | 19 | 30 | — | 30 | 11 | 19 | 30 | — | 104 | % | 80 | % | |||||||||||||||||||||||
| Francisco Underground | 100% | 14 | 3 | 11 | — | 14 | 14 | 3 | 11 | — | 14 | 71 | % | 65 | % | |||||||||||||||||||||||
Wildcat Hills Underground (5) | 100% | — | — | — | — | — | — | — | — | — | — | — | % | — | % | |||||||||||||||||||||||
| Somerville Central | 100% | 3 | 3 | — | 3 | — | 3 | 3 | — | 3 | — | 103 | % | 68 | % | |||||||||||||||||||||||
Cottage Grove (6) | 100% | — | — | — | — | — | — | — | — | — | — | — | % | — | % | |||||||||||||||||||||||
| Total | 333 | 172 | 161 | 267 | 66 | |||||||||||||||||||||||||||||||||
| Western U.S. Mining: | ||||||||||||||||||||||||||||||||||||||
| El Segundo/Lee Ranch | 100% | 34 | 29 | 5 | 34 | — | 34 | 29 | 5 | 34 | — | 87 | % | 100 | % | |||||||||||||||||||||||
Kayenta (7) | 100% | — | — | — | — | — | — | — | — | — | — | — | % | — | % | |||||||||||||||||||||||
| Twentymile | 100% | 5 | 3 | 2 | — | 5 | 5 | 3 | 2 | — | 5 | 119 | % | 67 | % | |||||||||||||||||||||||
| Total | 39 | 32 | 7 | 34 | 5 | |||||||||||||||||||||||||||||||||
| Total Assigned | 3,138 | 204 | 2,934 | 2,804 | 334 | |||||||||||||||||||||||||||||||||
•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 | ||||||||
ASSIGNED AND UNASSIGNED PROVEN AND PROBABLE COAL RESERVES (8) | ||||||||||||||||||||||||||||||
| AS OF DECEMBER 31, 2019 | ||||||||||||||||||||||||||||||
| (Tons in millions) | ||||||||||||||||||||||||||||||
| Attributable Ownership | 100% Project Basis | |||||||||||||||||||||||||||||
| Proven and | Proven and | |||||||||||||||||||||||||||||
| Total Tons | Probable | Total Tons | Probable | |||||||||||||||||||||||||||
| Coal Seam Location | Assigned | Unassigned | Reserves | Proven | Probable | Assigned | Unassigned | Reserves | Proven | Probable | ||||||||||||||||||||
| Seaborne Thermal Mining (New South Wales) | 250 | — | 250 | 203 | 47 | 283 | — | 283 | 211 | 72 | ||||||||||||||||||||
| Seaborne Metallurgical Mining: | ||||||||||||||||||||||||||||||
| Alabama | 53 | — | 53 | 52 | 1 | 53 | — | 53 | 52 | 1 | ||||||||||||||||||||
| New South Wales | 18 | — | 18 | 2 | 16 | 18 | — | 18 | 2 | 16 | ||||||||||||||||||||
| Queensland | 136 | 90 | 226 | 184 | 42 | 170 | 120 | 290 | 232 | 58 | ||||||||||||||||||||
| Total | 207 | 90 | 297 | 238 | 59 | |||||||||||||||||||||||||
| Powder River Basin Mining (Wyoming) | 2,309 | — | 2,309 | 2,202 | 107 | 2,309 | — | 2,309 | 2,202 | 107 | ||||||||||||||||||||
| Midwestern U.S. Mining: | ||||||||||||||||||||||||||||||
| Illinois | 52 | 719 | 771 | 333 | 438 | 52 | 719 | 771 | 333 | 438 | ||||||||||||||||||||
| Indiana | 281 | 6 | 287 | 208 | 79 | 281 | 6 | 287 | 208 | 79 | ||||||||||||||||||||
Kentucky (10) | — | 97 | 97 | 44 | 53 | — | 97 | 97 | 44 | 53 | ||||||||||||||||||||
| Total | 333 | 822 | 1,155 | 585 | 570 | |||||||||||||||||||||||||
| Western U.S. Mining: | ||||||||||||||||||||||||||||||
Arizona (7) | — | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||
| New Mexico | 34 | — | 34 | 34 | — | 34 | — | 34 | 34 | — | ||||||||||||||||||||
| Colorado | 5 | — | 5 | 5 | — | 5 | — | 5 | 5 | — | ||||||||||||||||||||
| Total | 39 | — | 39 | 39 | — | |||||||||||||||||||||||||
| Total Proven and Probable | 3,138 | 912 | 4,050 | 3,267 | 783 | |||||||||||||||||||||||||
SUMMARY COAL RESERVES AT END OF THE FISCAL YEAR ENDED DECEMBER 31, 2022 (1) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| (Tons in millions) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Peabody | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Mining | Coal | Proven Coal Reserves | Probable Coal Reserves | Total Coal Reserves | Interest | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Segment / Mining Complex | Country | State | Stage | Method | Type | Amount | Quality | Amount | Quality | Amount | Quality | (10) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Seaborne Thermal Mining:(2)(4) | Tons | %Ash | %Sulfur | Kcal/kg(6) | Tons | %Ash | %Sulfur | Kcal/kg(6) | Tons | %Ash | %Sulfur | Kcal/kg(6) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Wilpinjong | AUS | NSW | P | S | T | 63 | 24.2 | 0.5 | 5,953 | 4 | 30.4 | 0.4 | 5,422 | 67 | 24.5 | 0.5 | 5,924 | 100 | % | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Wambo Opencut (9) | AUS | NSW | P | S | T | 29 | 10.9 | 0.3 | 6,448 | 2 | 10.6 | 0.3 | 6,478 | 31 | 10.9 | 0.3 | 6,450 | 50 | % | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Wambo Underground | AUS | NSW | P | U | T | 2 | 13.7 | 0.4 | 6,473 | 3 | 12.2 | 0.4 | 6,588 | 5 | 12.9 | 0.4 | 6,534 | 100 | % | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| South Wambo | AUS | NSW | E | U | T/C | — | — | — | — | 74 | 9.8 | 0.3 | 7,034 | 74 | 9.8 | 0.3 | 7,034 | 100 | % | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Total | 94 | 83 | 177 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Seaborne Metallurgical Mining:(3)(4) | Tons | %Ash | %Sulfur | VM%(7) | Tons | %Ash | %Sulfur | VM%(7) | Tons | %Ash | %Sulfur | VM%(7) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Shoal Creek | USA | AL | P | U | C | 15 | 10.0 | 0.7 | 30.2 | 2 | 10.0 | 0.7 | 30.2 | 17 | 10.0 | 0.7 | 30.2 | 100 | % | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Coppabella | AUS | QLD | P | S | P | 6 | 9.3 | 0.2 | 9.9 | 4 | 9.8 | 0.2 | 8.5 | 10 | 9.5 | 0.2 | 9.3 | 73.3 | % | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Moorvale | AUS | QLD | P | S | C/P/T | 4 | 11.4 | 0.3 | 16.5 | — | — | — | — | 4 | 11.4 | 0.3 | 16.5 | 73.3 | % | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Metropolitan | AUS | NSW | P | U | C/T | 3 | 13.9 | 0.4 | 18.6 | 7 | 13.8 | 0.4 | 18.7 | 10 | 13.8 | 0.4 | 18.6 | 100 | % | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| North Goonyella | AUS | QLD | D | U | C | 46 | 7.4 | 0.5 | 21.4 | 24 | 7.5 | 0.5 | 21.1 | 70 | 7.4 | 0.5 | 21.3 | 100 | % | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Moorvale South | AUS | QLD | P | S | C/P | 3 | 11.1 | 0.4 | 18.4 | 2 | 9.8 | 0.4 | 17.4 | 5 | 10.6 | 0.4 | 18.0 | 73.3 | % | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Middlemount (9) | AUS | QLD | P | S | C/P | 25 | 10.3 | 0.4 | 18.0 | 9 | 10.3 | 0.4 | 18.0 | 34 | 10.3 | 0.4 | 18.0 | 50.0 | % | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Total | 102 | 48 | 150 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Powder River Basin Mining:(5) | Tons | %Ash | %Sulfur | Btu(8) | Tons | %Ash | %Sulfur | Btu(8) | Tons | %Ash | %Sulfur | Btu(8) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| North Antelope Rochelle | USA | WY | P | S | T | 1,316 | 4.4 | 0.2 | 8,889 | 107 | 4.5 | 0.2 | 8,965 | 1,423 | 4.4 | 0.2 | 8,895 | 100 | % | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Caballo | USA | WY | P | S | T | 274 | 5.1 | 0.3 | 8,517 | 68 | 5.6 | 0.3 | 8,313 | 342 | 5.2 | 0.3 | 8,476 | 100 | % | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Rawhide | USA | WY | P | S | T | 115 | 5.6 | 0.4 | 8,278 | 2 | 5.2 | 0.3 | 8,362 | 117 | 5.6 | 0.4 | 8,279 | 100 | % | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Total | 1,705 | 177 | 1,882 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other U.S. Thermal Mining:(5) | Tons | %Ash | %Sulfur | Btu(8) | Tons | %Ash | %Sulfur | Btu(8) | Tons | %Ash | %Sulfur | Btu(8) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Bear Run | USA | IN | P | S | T | 84 | 10.6 | 3.1 | 11,058 | 52 | 10.0 | 2.5 | 11,045 | 136 | 10.4 | 2.9 | 11,055 | 100 | % | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| El Segundo/Lee Ranch | USA | NM | P | S | T | 13 | 15.8 | 0.9 | 9,249 | 1 | 12.3 | 0.7 | 9,526 | 14 | 15.6 | 0.9 | 9,266 | 100 | % | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Gateway North | USA | IL | P | U | T | 38 | 8.9 | 2.9 | 10,888 | 5 | 9.0 | 3.0 | 10,874 | 43 | 8.9 | 2.9 | 10,886 | 100 | % | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Twentymile | USA | CO | P | U | T | 10 | 10.7 | 0.5 | 11,280 | 1 | 10.2 | 0.5 | 11,230 | 11 | 10.6 | 0.5 | 11,272 | 100 | % | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Wild Boar | USA | IN | P | S | T | 7 | 8.3 | 2.4 | 11,010 | 8 | 8.4 | 2.7 | 11,470 | 15 | 8.4 | 2.6 | 11,265 | 100 | % | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Francisco Underground | USA | IN | P | U | T | 3 | 8.7 | 2.9 | 11,500 | 4 | 9.0 | 3.3 | 11,455 | 7 | 8.9 | 3.1 | 11,480 | 100 | % | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Total | 155 | 71 | 226 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Grand total | 2,056 | 379 | 2,435 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| 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 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Peabody Energy Corporation | ||||||||
| ASSIGNED AND UNASSIGNED - RESERVE CONTROL AND MINING METHOD | ||||||||||||||||||||||||
| AS OF DECEMBER 31, 2019 | ||||||||||||||||||||||||
| (Tons in millions) | ||||||||||||||||||||||||
| Attributable Ownership | 100% Project Basis | |||||||||||||||||||||||
| Reserve Control | Mining Method | Reserve Control | Mining Method | |||||||||||||||||||||
| Coal Seam Location | Owned | Leased | Surface | Underground | Owned | Leased | Surface | Underground | ||||||||||||||||
| Seaborne Thermal Mining (New South Wales) | — | 250 | 140 | 110 | — | 283 | 173 | 110 | ||||||||||||||||
| Seaborne Metallurgical Mining: | ||||||||||||||||||||||||
| Alabama | — | 53 | — | 53 | — | 53 | — | 53 | ||||||||||||||||
| New South Wales | — | 18 | — | 18 | — | 18 | — | 18 | ||||||||||||||||
| Queensland | — | 226 | 60 | 166 | — | 290 | 96 | 194 | ||||||||||||||||
| Total | — | 297 | 60 | 237 | ||||||||||||||||||||
| Powder River Basin Mining (Wyoming) | — | 2,309 | 2,309 | — | — | 2,309 | 2,309 | — | ||||||||||||||||
| Midwestern U.S. Mining: | ||||||||||||||||||||||||
| Illinois | 770 | 1 | — | 771 | 770 | 1 | — | 771 | ||||||||||||||||
| Indiana | 124 | 163 | 274 | 13 | 124 | 163 | 274 | 13 | ||||||||||||||||
Kentucky (10) | 33 | 64 | — | 97 | 33 | 64 | — | 97 | ||||||||||||||||
| Total | 927 | 228 | 274 | 881 | ||||||||||||||||||||
| Western U.S. Mining: | ||||||||||||||||||||||||
Arizona (7) | — | — | — | — | — | — | — | — | ||||||||||||||||
| New Mexico | 29 | 5 | 34 | — | 29 | 5 | 34 | — | ||||||||||||||||
| Colorado | 3 | 2 | — | 5 | 3 | 2 | — | 5 | ||||||||||||||||
| Total | 32 | 7 | 34 | 5 | ||||||||||||||||||||
| Total Proven and Probable | 959 | 3,091 | 2,817 | 1,233 | ||||||||||||||||||||
SUMMARY COAL RESOURCES AT END OF THE FISCAL YEAR ENDED DECEMBER 31, 2022 (1) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| (Tons in millions) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Measured and Indicated | Peabody | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Mining | Coal | Measured Coal Resources | Indicated Coal Resources | Coal Resources | Inferred Coal Resources | Interest | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Deposit | Country | State | Stage | Method | Type | Amount | Quality | Amount | Quality | Amount | Quality | Amount | Quality | (10) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Seaborne Thermal Mining:(2)(4) | Tons | %Ash | %Sulfur | Kcal/kg(6) | Tons | %Ash | %Sulfur | Kcal/kg(6) | Tons | %Ash | %Sulfur | Kcal/kg(6) | Tons | %Ash | %Sulfur | Kcal/kg(5) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Wilpinjong | AUS | NSW | P | S | T | 103 | 23.0 | 0.5 | 6,055 | 25 | 25.4 | 0.5 | 5,860 | 128 | 23.5 | 0.5 | 6,017 | 6 | 27.3 | 0.5 | 5,698 | 100 | % | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Wambo Opencut (9) | AUS | NSW | P | S/U | T | 191 | 21.6 | 0.4 | 5,731 | 154 | 21.5 | 0.4 | 5,764 | 345 | 21.6 | 0.4 | 5,746 | 259 | 19.9 | 0.4 | 5,864 | 50 | % | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Wambo South | AUS | NSW | E | U | T/C | 219 | 21.5 | 0.3 | 6,068 | 83 | 27.2 | 0.3 | 5,571 | 302 | 23.1 | 0.3 | 5,931 | 47 | 36.3 | 0.3 | 4,745 | 100 | % | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Total | 513 | 262 | 775 | 312 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Seaborne Metallurgical Mining:(3)(4) | Tons | %Ash | %Sulfur | VM%(7) | Tons | %Ash | %Sulfur | VM%(7) | Tons | %Ash | %Sulfur | VM%(7) | Tons | %Ash | %Sulfur | VM%(7) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Shoal Creek | USA | AL | P | U | C | 40 | 9.6 | 0.7 | 25.1 | 35 | 9.9 | 0.7 | 24.1 | 75 | 9.8 | 0.7 | 24.6 | 7 | 10.3 | 0.7 | 24.0 | 100 | % | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Metropolitan | AUS | NSW | P | U | C/T | 7 | 15.4 | 0.4 | 18.6 | 8 | 15.3 | 0.3 | 18.7 | 15 | 15.3 | 0.4 | 18.6 | 2 | 16.0 | 0.3 | 19.0 | 100 | % | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Coppabella | AUS | QLD | P | S | P | 13 | 15.8 | 0.3 | 13.1 | 48 | 14.3 | 0.2 | 12.8 | 61 | 14.6 | 0.2 | 12.9 | 73 | 15.5 | 0.2 | 12.3 | 73.3 | % | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Moorvale | AUS | QLD | P | S | P | 14 | 18.5 | 0.3 | 16.7 | 14 | 17.2 | 0.3 | 16.6 | 28 | 17.9 | 0.3 | 16.7 | 5 | 15.9 | 0.3 | 16.7 | 73.3 | % | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Moorvale South | AUS | QLD | P | S | C/P | 3 | 18.3 | 0.4 | 18.4 | 7 | 18.2 | 0.4 | 18.3 | 10 | 18.2 | 0.4 | 18.3 | 6 | 16.8 | 0.4 | 17.7 | 73.3 | % | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| NGC GLB2 | AUS | QLD | E | U | C | — | — | — | — | 1 | 15.3 | 0.6 | 20.7 | 1 | 15.3 | 0.6 | 20.7 | 8 | 13.6 | 0.5 | 20.7 | 100 | % | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Coppabella North | AUS | QLD | E | U | P | 255 | 15.8 | 0.3 | 14.6 | 102 | 16.8 | 0.3 | 14.6 | 357 | 16.1 | 0.3 | 14.6 | 12 | 16.5 | 0.3 | 14.3 | 75.5 | % | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Yeerun | AUS | QLD | E | S | P | 16 | 16.0 | 0.4 | 14.3 | 57 | 16.2 | 0.5 | 15.0 | 73 | 16.2 | 0.4 | 14.8 | 46 | 17.8 | 0.5 | 14.7 | 83.0 | % | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Moorvale North | AUS | QLD | E | U | P | 21 | 26.0 | 0.4 | 12.9 | 25 | 24.5 | 0.5 | 13.2 | 46 | 25.2 | 0.4 | 13.1 | 25 | 23.2 | 0.5 | 13.4 | 73.3 | % | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Gundyer | AUS | QLD | E | U | P | — | — | — | — | 54 | 16.4 | 0.2 | 19.7 | 54 | 16.4 | 0.2 | 19.7 | 70 | 18.3 | 0.2 | 18.3 | 90.0 | % | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Total | 369 | 351 | 720 | 254 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Powder River Basin Mining:(5) | Tons | %Ash | %Sulfur | Btu(8) | Tons | %Ash | %Sulfur | Btu(8) | Tons | %Ash | %Sulfur | Btu(8) | Tons | %Ash | %Sulfur | Btu(8) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Caballo | USA | WY | P | S | T | 15 | 5.3 | 0.4 | 8,218 | 65 | 5.2 | 0.4 | 8,211 | 80 | 5.2 | 0.4 | 8,212 | 1 | 5.5 | 0.4 | 8,263 | 100 | % | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Rawhide | USA | WY | P | S | T | 1 | 5.4 | 0.4 | 8,277 | 95 | 5.2 | 0.3 | 8,356 | 96 | 5.2 | 0.3 | 8,355 | 7 | 5.7 | 0.4 | 8,252 | 100 | % | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Total | 16 | 160 | 176 | 8 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other U.S. Thermal Mining:(5) | Tons | %Ash | %Sulfur | Btu(8) | Tons | %Ash | %Sulfur | Btu(8) | Tons | %Ash | %Sulfur | Btu(8) | Tons | %Ash | %Sulfur | Btu(8) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Bear Run | USA | IN | P | S | T | 18 | 14.6 | 3.5 | 10,860 | 51 | 16.8 | 3.5 | 10,450 | 69 | 16.3 | 3.5 | 10,550 | 37 | 16.3 | 3.5 | 10,545 | 100 | % | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| El Segundo/Lee Ranch | USA | NM | P | S | T | 1 | 17.1 | 1.1 | 9,491 | 5 | 16.5 | 1.0 | 9,475 | 6 | 16.6 | 1.0 | 9,478 | 2 | 17.4 | 1.2 | 9,280 | 100 | % | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Wild Boar | USA | IN | P | S | T | — | — | — | — | 3 | 12.9 | 6.1 | 10,940 | 3 | 12.9 | 5.4 | 11,020 | 1 | 12.9 | 5.9 | 10,960 | 100 | % | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Total | 19 | 59 | 78 | 40 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Grand total | 917 | 832 | 1,749 | 614 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Peabody Energy Corporation | ||||||||
| ASSIGNED AND UNASSIGNED PROVEN AND PROBABLE COAL RESERVES - SULFUR CONTENT | |||||||||||||||||||||||
| AS OF DECEMBER 31, 2019 | |||||||||||||||||||||||
| (Tons in millions) | |||||||||||||||||||||||
| Attributable Ownership | 100% Project Basis | ||||||||||||||||||||||
Sulfur Content (1) | Sulfur Content (1) | ||||||||||||||||||||||
| <1.2 lbs. | >1.2 to 2.5 lbs. | >2.5 lbs. | <1.2 lbs. | >1.2 to 2.5 lbs. | >2.5 lbs. | As | |||||||||||||||||
| Sulfur Dioxide | Sulfur Dioxide | Sulfur Dioxide | Sulfur Dioxide | Sulfur Dioxide | Sulfur Dioxide | Received | |||||||||||||||||
| Type of | per | per | per | per | per | per | Btu | ||||||||||||||||
| Coal Seam Location | Coal | Million Btu | Million Btu | Million Btu | Million Btu | Million Btu | Million Btu | per Pound (2) | |||||||||||||||
| Seaborne Thermal Mining (New South Wales) | T/C | 250 | — | — | 283 | — | — | 10,700 | |||||||||||||||
| Seaborne Metallurgical Mining: | |||||||||||||||||||||||
| Alabama | C | 53 | — | — | 53 | — | — | 12,700 | |||||||||||||||
| New South Wales | C/P/T | 18 | — | — | 18 | — | — | 12,600 | |||||||||||||||
| Queensland | C/P/T | 226 | — | — | 290 | — | — | 12,400 | |||||||||||||||
| Total | 297 | — | — | ||||||||||||||||||||
| Powder River Basin Mining (Wyoming) | T | 2,257 | 52 | — | 2,257 | 52 | — | 8,700 | |||||||||||||||
| Midwestern U.S. Mining: | |||||||||||||||||||||||
| Illinois | T | — | — | 771 | — | — | 771 | 10,800 | |||||||||||||||
| Indiana | T | 4 | 25 | 258 | 4 | 25 | 258 | 11,000 | |||||||||||||||
Kentucky (10) | T | — | — | 97 | — | — | 97 | 11,800 | |||||||||||||||
| Total | 4 | 25 | 1,126 | ||||||||||||||||||||
| Western U.S. Mining: | |||||||||||||||||||||||
Arizona (7) | T | — | — | — | — | — | — | — | |||||||||||||||
| New Mexico | T | 4 | 23 | 7 | 4 | 23 | 7 | 9,150 | |||||||||||||||
| Colorado | T | 5 | — | — | 5 | — | — | 11,200 | |||||||||||||||
| Total | 9 | 23 | 7 | ||||||||||||||||||||
| Total Proven and Probable | 2,817 | 100 | 1,133 | ||||||||||||||||||||
| estimated on an as-shipped basis for reserves, and an in-situ moisture basis for resources. | |||||
| (3) | The moisture condition for the Seaborne Metallurgical Mining segment coal quality is on an air-dry basis, except for Shoal Creek Mine which is on a dry basis. | ||||
| (4) | |||||
The quality and quantity estimates for U.S. thermal reserves are calculated on as-shipped moisture basis; the quality and quantity estimates for U.S. thermal resources are calculated on an in situ moisture basis. | |||||
| (6) | Kcal/kg (kilocalories per kilogram) is the net calorific value (net heating value) of coal, except for Wambo Opencut which is estimated as gross calorific value. | ||||
| (7) | VM (volatile matter) represents the proportion of certain organic and mineral components in coal, for example, water, carbon dioxide, or sulfur dioxide. Volatile matter is inversely related to coal rank. | ||||
| (8) | Btu (British thermal unit) is the gross heating value of coal per pound, which includes the weight of moisture in | ||||
| (9) | Reserve and resource data is maintained and provided by joint venture managing partners utilizing the Australasian Code for Reporting of | ||||
| (10) | The quantities of reserves and resources are disclosed at Peabody’s proportional ownership share. | ||||
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.
| 48 | ||||||||
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.
| 49 | ||||||||
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) | ||||||||||||||||||||||||||||||||||||||
| December 31, 2022 | December 31, 2021 | |||||||||||||||||||||||||||||||||||||
Coal Reserves (2)(3)(4) | Tons | %Ash | %Sulfur | Btu | % Mine Yield(5) | Tons | ||||||||||||||||||||||||||||||||
| Proven | 1,316 | 4.4 | 0.2 | 8,889 | 100 | % | 1,378 | |||||||||||||||||||||||||||||||
| Probable | 107 | 4.5 | 0.2 | 8,965 | 100 | % | 106 | |||||||||||||||||||||||||||||||
| Total | 1,423 | 1,484 | ||||||||||||||||||||||||||||||||||||
| Year-over-year decrease | (4) | % | ||||||||||||||||||||||||||||||||||||
The year-over-year decrease in the quantity of coal reserves was driven by production depletion.
| Economic recoverability is based upon an estimated average sales price per ton of $14.64 for the five-year period ending December 31, 2027 and assumed escalation of 2.0% per annum during the subsequent period through the end of the LOM plan. | |||||
| (2) | The | ||||
| (3) | The quality of coal reserves is estimated on an as-shipped basis. | ||||
| (4) | The quantity of coal reserves is estimated on a saleable product basis, which takes into consideration 92% mining recovery. The results of the LOM planning process demonstrate the economic recoverability of the coal reserve estimates. | ||||
| (5) | Mine | ||||
| 50 | ||||||||
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.
| 51 | ||||||||
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) | ||||||||||||||||||||||||||||||||||||||
| December 31, 2022 | December 31, 2021 | |||||||||||||||||||||||||||||||||||||
Coal Reserves (2)(4)(5)(6) | Tons | %Ash | %Sulfur | %VM | % Mine Yield (7) | Tons | ||||||||||||||||||||||||||||||||
| Proven | 15 | 10.0 | 0.7 | 30.2 | 36 | % | 16 | |||||||||||||||||||||||||||||||
| Probable | 2 | 10.0 | 0.7 | 30.2 | 36 | % | 2 | |||||||||||||||||||||||||||||||
| Total | 17 | 18 | ||||||||||||||||||||||||||||||||||||
| Year-over-year decrease | (6) | % | ||||||||||||||||||||||||||||||||||||
| December 31, 2022 | December 31, 2021 | |||||||||||||||||||||||||||||||||||||
Coal Resources (2)(3)(4)(5) | Tons | %Ash | %Sulfur | VM% | Tons | |||||||||||||||||||||||||||||||||
| Measured | 40 | 9.6 | 0.7 | 25.1 | 40 | |||||||||||||||||||||||||||||||||
| Indicated | 35 | 9.9 | 0.7 | 24.1 | 35 | |||||||||||||||||||||||||||||||||
| Measured and indicated | 75 | 9.8 | 0.7 | 24.6 | 75 | |||||||||||||||||||||||||||||||||
| Inferred | 7 | 10.2 | 0.7 | 24.0 | 7 | |||||||||||||||||||||||||||||||||
| Total | 82 | 82 | ||||||||||||||||||||||||||||||||||||
The year-over-year decrease in coal reserves reflects 2022 production depletion.
| (2) | The quality of coal reserves | ||||
| (3) | The quantity of resource estimates are on an in situ basis, which doesn’t take into consideration coal loss during mining and | ||||
| (4) | The coal resource boundary is established by considering various factors, including results from drill hole analyses, coal control, geological features, faults and other surface features. | ||||
| (5) | The cut-off grade and metallurgical recovery are not limiting factors for the reserve and resource estimates due to relatively consistent coal quality and float recovery from the lab results within the assessed area. The historically mined coal thickness has been used as | ||||
| mine’s actual performance in the last two decades. | |||||
| The | |||||
| (7) | Mine yield is the ratio of estimated saleable product coal over ROM coal tons with mainly processing loss considered. | ||||
| 52 | ||||||||
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.
| 53 | ||||||||
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) | ||||||||||||||||||||||||||||||||||||||
| December 31, 2022 | December 31, 2021 | |||||||||||||||||||||||||||||||||||||
Coal Reserves (5)(6) | Tons | %Ash | %Sulfur | Kcal/kg | % Mine Yield(7) | Tons | ||||||||||||||||||||||||||||||||
| Proven | 63 | 24.2 | 0.5 | 5,953 | 82 | % | 71 | |||||||||||||||||||||||||||||||
| Probable | 4 | 30.4 | 0.4 | 5,422 | 82 | % | 5 | |||||||||||||||||||||||||||||||
| Total | 67 | 76 | ||||||||||||||||||||||||||||||||||||
| Year-over-year decrease | (12) | % | ||||||||||||||||||||||||||||||||||||
| December 31, 2022 | December 31, 2021 | |||||||||||||||||||||||||||||||||||||
Coal Resources (2)(3)(4) | Tons | %Ash | %Sulfur | Kcal/kg | Tons | |||||||||||||||||||||||||||||||||
| Measured | 103 | 23.0 | 0.5 | 6,055 | 103 | |||||||||||||||||||||||||||||||||
| Indicated | 25 | 25.4 | 0.5 | 5,860 | 25 | |||||||||||||||||||||||||||||||||
| Measured and indicated | 128 | 23.5 | 0.5 | 6,017 | 128 | |||||||||||||||||||||||||||||||||
| Inferred | 6 | 27.3 | 0.5 | 5,698 | 6 | |||||||||||||||||||||||||||||||||
| Total | 134 | 134 | ||||||||||||||||||||||||||||||||||||
The year-over-year decrease in the quantity of coal reserves was driven by production depletion.
| (1) | Economic recoverability is based upon product-specific estimated average sales prices per ton of $51.99 for the five-year period ending December | ||||
| (2) | The quality of coal resources is on an in | ||||
| (3) | The quantity of coal resource estimates is on an in situ basis, which does not take into consideration coal loss during mining and processing. | ||||
| (4) | Besides the | ||||
| (5) | The quality of coal reserves is based on an air-dry basis. It is the laboratory results from the core samples with adjustments that reflect the reconciliation results from actual production. | ||||
| (6) | The quantity of | ||||
| (7) | Mine | ||||
| Peabody Energy Corporation | 2022 Form 10-K | 54 | ||||||
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.
| Peabody Energy Corporation | 2022 Form 10-K | 55 | ||||||
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) | ||||||||||||||||||||||||||||||||||||||
| December 31, 2022 | December 31, 2021 | |||||||||||||||||||||||||||||||||||||
Coal Reserves (5)(6) | Tons | %Ash | %Sulfur | %VM | % Mine Yield (7) | Tons | ||||||||||||||||||||||||||||||||
| Proven | 13 | 10.4 | 0.3 | 13.9 | 74 | % | 14 | |||||||||||||||||||||||||||||||
| Probable | 6 | 9.8 | 0.3 | 11.5 | 76 | % | 6 | |||||||||||||||||||||||||||||||
| Total | 19 | 20 | ||||||||||||||||||||||||||||||||||||
| Year-over-year decrease | (5) | % | ||||||||||||||||||||||||||||||||||||
| December 31, 2022 | December 31, 2021 | |||||||||||||||||||||||||||||||||||||
Coal Resources (2)(3)(4) | Tons | %Ash | %Sulfur | VM% | Tons | |||||||||||||||||||||||||||||||||
| Measured | 30 | 17.3 | 0.3 | 15.3 | 34 | |||||||||||||||||||||||||||||||||
| Indicated | 69 | 15.3 | 0.3 | 14.1 | 69 | |||||||||||||||||||||||||||||||||
| Measured and indicated | 99 | 15.9 | 0.3 | 14.5 | 103 | |||||||||||||||||||||||||||||||||
| Inferred | 84 | 15.6 | 0.3 | 12.9 | 84 | |||||||||||||||||||||||||||||||||
| Total | 183 | 187 | ||||||||||||||||||||||||||||||||||||
| 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.
| Peabody Energy Corporation | 2022 Form 10-K | 56 | ||||||
| (1) | Economic recoverability is based upon product-specific estimated average sales prices per ton of $122.75 for the five-year period ending December 31, 2027 and assumed escalation of 2% to 3% per annum during the subsequent period through the end of the LOM plan. | |||||||
| (2) | The quality of coal resources is estimated on an in situ, air-dry basis. | |||||||
| (3) | The quantity of coal resource is estimated on an in situ basis, which doesn’t take into consideration coal loss during mining and processing. | |||||||
| (4) | Besides the results from drill hole analyses, the resource estimates are based on the following criteria: | |||||||
| — | Open cut resources are limited to an area defined by pit shell with RF150 (revenue factor 150%), with exception of Moorvale South MDL 3034 open cut resources are limited to 150m depth of cover | |||||||
| — | 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 | |||||||
| — | Underground resources depth cutoff at 500m depth of cover, with exception of Moorvale Mine depth cutoff at 300m depth of cover | |||||||
| — | A seam quality cut-off greater than 50% raw ash (a.d.) is excluded from resources | |||||||
| — | 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. | |||||||
| (6) | The quantity of coal reserves is estimated on a saleable product basis which takes into consideration of mining and processing loss. The economic results from the LOM planning process demonstrate the economic viability of the coal reserve estimate. | |||||||
| (7) | Mine yield is the ratio of estimated saleable product coal over ROM coal tons with mainly processing loss considered. | |||||||
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 26.21. “Commitments and Contingencies” to the accompanying consolidated financial statements for a description of ourPeabody’s pending legal proceedings, which information is incorporated herein by reference.
| Peabody Energy Corporation | 2022 Form 10-K | 57 | ||||||
Item 4. Mine Safety Disclosures.
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Share Relinquishments
Share Repurchase ProgramsProgram
Similar to the payment of dividends as described above, the same agreements with the Company’s surety bond providers prohibit share repurchases imposedthrough the earlier of December 31, 2025, or the maturity of the Credit Agreement (currently March 31, 2025) unless otherwise agreed to by ourthe 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 instrumentsagreements in effect at the time any repurchases are discussedmade.
| Peabody Energy Corporation | 2022 Form 10-K | 58 | ||||||
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 Part II, Item 7. “Management’s Discussionwhich 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 Analysis$21.6 million aggregate principal amount of Financial Conditionthe 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 Resultsthe 2024 Peabody Notes was made in reliance on the exemption from registration provided in Section 3(a)(9) under the Securities Act of Operations.” We suspended share repurchases1933, based in 2019part 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 additional repurchases are planned.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, 2019:2022:
| Period | Total Number of Shares Purchased (1) | Average Price Paid per Share | Total Number of Shares Purchased as Part of Publicly Announced Program | Maximum Dollar Value of Shares that May Yet Be Used to Repurchase Shares Under the Publicly Announced Program (In millions) | ||||||||||
| October 1 through October 31, 2019 | 2,024,905 | $ | 14.68 | 2,024,500 | $ | 160.5 | ||||||||
| November 1 through November 30, 2019 | 1,085 | 9.10 | — | 160.5 | ||||||||||
| December 1 through December 31, 2019 | 912 | 9.09 | — | 160.5 | ||||||||||
| Total | 2,026,902 | 14.67 | 2,024,500 | |||||||||||
| Period | Total Number of Shares Purchased (1) | Average Price Paid per Share | Total Number of Shares Purchased as Part of Publicly Announced Program | Maximum Dollar Value of Shares that May Yet Be Used to Repurchase Shares Under the Publicly Announced Program (In millions) | ||||||||||||||||||||||
| October 1 through October 31, 2022 | — | $ | — | — | $ | 160.5 | ||||||||||||||||||||
| November 1 through November 30, 2022 | — | — | — | 160.5 | ||||||||||||||||||||||
| December 1 through December 31, 2022 | — | — | — | 160.5 | ||||||||||||||||||||||
| 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 ourPeabody’s common stock from April 4, 2017, the date our common stock began trading following the effective date of our Plan, through December 31, 2019, with the cumulative total return of the following indices: (i) the S&P MidCap 400 Stock Index and (ii) aCustom Composite Index (a peer group comprised of Arch Coal,Resources, Inc., Hallador Energy Co., and Warrior Met Coal, Inc. (Custom Composite Index)). The Custom Composite Index reflects publicly listed U.S. companies within the coal industry of similar size or product type. Cloud Peak Energy Inc. was removed from our updated Custom Composite Index as it was delisted by the New York Stock Exchange on March 26, 2019. Master Limited Partnerships were excluded.
The graph assumes that the value of the investment in BTU and each index was $100 at April 4, 2017 for BTU and the Custom Composite Index (Warrior Met Coal, Inc. began trading on the New York Stock Exchange on April 13, 2017) and at MarchDecember 31, 2017, for the S&P Midcap 400 Index.2017. The graph also assumes that all dividends were reinvested and that the investments were held through December 31, 2019.
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.
| Peabody Energy Corporation | ||||||||
| Successor | Predecessor | |||||||||||||||||||||
| Year Ended December 31, | April 2 through December 31, 2017 | January 1 through April 1, 2017 | Year Ended December 31, | |||||||||||||||||||
| 2019 | 2018 | 2016 | 2015 | |||||||||||||||||||
| (In millions, except per share data) | ||||||||||||||||||||||
| Results of Operations Data | ||||||||||||||||||||||
| Total revenues | $ | 4,623.4 | $ | 5,581.8 | $ | 4,252.6 | $ | 1,326.2 | $ | 4,715.3 | $ | 5,609.2 | ||||||||||
| Costs and expenses | 4,561.7 | 4,920.2 | 3,588.8 | 1,113.7 | 4,935.1 | 6,995.0 | ||||||||||||||||
| Operating profit (loss) | 61.7 | 661.6 | 663.8 | 212.5 | (219.8 | ) | (1,385.8 | ) | ||||||||||||||
| Interest expense, net | 117.2 | 117.7 | 135.0 | 30.2 | 322.4 | 525.5 | ||||||||||||||||
| Net periodic benefit costs, excluding service cost | 19.4 | 18.1 | 21.9 | 14.4 | 57.1 | 79.0 | ||||||||||||||||
| Net mark-to-market adjustment on actuarially determined liabilities | 67.4 | (125.5 | ) | (45.2 | ) | — | — | — | ||||||||||||||
| Reorganization items, net | — | (12.8 | ) | — | 627.2 | 159.0 | — | |||||||||||||||
| (Loss) income from continuing operations before income taxes | (142.3 | ) | 664.1 | 552.1 | (459.3 | ) | (758.3 | ) | (1,990.3 | ) | ||||||||||||
| Income tax provision (benefit) | 46.0 | 18.4 | (161.0 | ) | (263.8 | ) | (94.5 | ) | (207.1 | ) | ||||||||||||
| (Loss) income from continuing operations, net of income taxes | (188.3 | ) | 645.7 | 713.1 | (195.5 | ) | (663.8 | ) | (1,783.2 | ) | ||||||||||||
| Income (loss) from discontinued operations, net of income taxes | 3.2 | 18.1 | (19.8 | ) | (16.2 | ) | (57.6 | ) | (175.0 | ) | ||||||||||||
| Net (loss) income | (185.1 | ) | 663.8 | 693.3 | (211.7 | ) | (721.4 | ) | (1,958.2 | ) | ||||||||||||
| Less: Series A Convertible Preferred Stock dividends | — | 102.5 | 179.5 | — | — | — | ||||||||||||||||
| Less: Net income attributable to noncontrolling interests | 26.2 | 16.9 | 15.2 | 4.8 | 7.9 | 7.1 | ||||||||||||||||
| Net (loss) income attributable to common stockholders | $ | (211.3 | ) | $ | 544.4 | $ | 498.6 | $ | (216.5 | ) | $ | (729.3 | ) | $ | (1,965.3 | ) | ||||||
| Basic EPS - (Loss) income from continuing operations | $ | (2.07 | ) | $ | 4.35 | $ | 3.85 | $ | (10.93 | ) | $ | (36.72 | ) | $ | (98.65 | ) | ||||||
| Diluted EPS - (Loss) income from continuing operations | $ | (2.07 | ) | $ | 4.28 | $ | 3.81 | $ | (10.93 | ) | $ | (36.72 | ) | $ | (98.65 | ) | ||||||
| Weighted average shares used in calculating basic EPS | 103.7 | 119.3 | 101.1 | 18.3 | 18.3 | 18.1 | ||||||||||||||||
| Weighted average shares used in calculating diluted EPS | 103.7 | 121.0 | 102.5 | 18.3 | 18.3 | 18.1 | ||||||||||||||||
| Dividends declared per share | $ | 2.410 | $ | 0.485 | $ | — | $ | — | $ | — | $ | 0.075 | ||||||||||
| Other Data | ||||||||||||||||||||||
| Tons produced | 164.7 | 182.1 | 142.7 | 45.6 | 175.6 | 208.7 | ||||||||||||||||
| Tons sold | 165.5 | 186.7 | 145.4 | 46.1 | 186.8 | 228.8 | ||||||||||||||||
| Net cash provided by (used in) continuing operations: | ||||||||||||||||||||||
| Operating activities | $ | 705.4 | $ | 1,516.9 | $ | 832.2 | $ | (804.8 | ) | $ | 33.6 | $ | 69.7 | |||||||||
| Investing activities | (261.3 | ) | (517.3 | ) | (93.4 | ) | 15.1 | (244.1 | ) | (290.0 | ) | |||||||||||
| Financing activities | (701.3 | ) | (1,025.2 | ) | (745.4 | ) | 952.3 | 907.9 | 267.7 | |||||||||||||
| Adjusted EBITDA | 837.1 | 1,379.3 | 1,145.3 | 341.3 | 532.0 | 432.4 | ||||||||||||||||
| Balance Sheet Data (at period end) | ||||||||||||||||||||||
| Total assets | $ | 6,542.8 | $ | 7,423.7 | $ | 8,181.2 | $ | 8,266.9 | $ | 11,777.7 | $ | 10,946.9 | ||||||||||
| Total long-term debt (including financing leases) | 1,310.8 | 1,367.0 | 1,460.8 | 1,881.4 | 7,791.4 | 6,241.2 | ||||||||||||||||
| Total stockholders’ equity | 2,672.5 | 3,451.6 | 3,655.8 | 3,131.9 | 181.5 | 751.7 | ||||||||||||||||
| Successor | Predecessor | |||||||||||||||||||||
| Year Ended December 31, | April 2 through December 31, 2017 | January 1 through April 1, 2017 | Year Ended December 31, | |||||||||||||||||||
| 2019 | 2018 | 2016 | 2015 | |||||||||||||||||||
| (Dollars in millions) | ||||||||||||||||||||||
| (Loss) income from continuing operations, net of income taxes | $ | (188.3 | ) | $ | 645.7 | $ | 713.1 | $ | (195.5 | ) | $ | (663.8 | ) | $ | (1,783.2 | ) | ||||||
| Depreciation, depletion and amortization | 601.0 | 679.0 | 521.6 | 119.9 | 465.4 | 572.2 | ||||||||||||||||
| Asset retirement obligation expenses | 58.4 | 53.0 | 41.2 | 14.6 | 41.8 | 45.5 | ||||||||||||||||
| Selling and administrative expenses related to debt restructuring | — | — | — | — | 21.5 | — | ||||||||||||||||
| Gain on formation of United Wambo Joint Venture | (48.1 | ) | — | — | — | — | — | |||||||||||||||
| Asset impairment | 270.2 | — | — | 30.5 | 247.9 | 1,277.8 | ||||||||||||||||
| Provision for North Goonyella equipment loss | 83.2 | 66.4 | — | — | — | — | ||||||||||||||||
| North Goonyella insurance recovery - equipment | (91.1 | ) | — | — | — | — | — | |||||||||||||||
| Changes in deferred tax asset valuation allowance and reserves and amortization of basis difference related to equity affiliates | (18.8 | ) | (18.3 | ) | (17.3 | ) | (5.2 | ) | (7.5 | ) | 3.9 | |||||||||||
| Interest expense | 144.0 | 149.3 | 119.7 | 32.9 | 298.6 | 465.4 | ||||||||||||||||
| Loss on early debt extinguishment | 0.2 | 2.0 | 20.9 | — | 29.5 | 67.8 | ||||||||||||||||
| Interest income | (27.0 | ) | (33.6 | ) | (5.6 | ) | (2.7 | ) | (5.7 | ) | (7.7 | ) | ||||||||||
| Net mark-to-market adjustment on actuarially determined liabilities | 67.4 | (125.5 | ) | (45.2 | ) | — | — | — | ||||||||||||||
| Reorganization items, net | — | (12.8 | ) | — | 627.2 | 159.0 | — | |||||||||||||||
| Gain on disposal of reclamation liability | — | — | (31.2 | ) | — | — | — | |||||||||||||||
| Gain on disposal of Burton Mine assets | — | — | (52.2 | ) | — | — | — | |||||||||||||||
| Break fees related to terminated asset sales | — | — | (28.0 | ) | — | — | — | |||||||||||||||
| Unrealized (gains) losses on economic hedges | (42.2 | ) | (18.3 | ) | 23.0 | (16.6 | ) | 39.8 | (2.2 | ) | ||||||||||||
| Unrealized (gains) losses on non-coal trading derivative contracts | (1.2 | ) | 0.7 | 1.5 | — | — | — | |||||||||||||||
| Fresh start coal inventory revaluation | — | — | 67.3 | — | — | — | ||||||||||||||||
| Fresh start take-or-pay contract-based intangible recognition | (16.6 | ) | (26.7 | ) | (22.5 | ) | — | — | — | |||||||||||||
| Income tax provision (benefit) | 46.0 | 18.4 | (161.0 | ) | (263.8 | ) | (94.5 | ) | (207.1 | ) | ||||||||||||
| Adjusted EBITDA | $ | 837.1 | $ | 1,379.3 | $ | 1,145.3 | $ | 341.3 | $ | 532.0 | $ | 432.4 | ||||||||||
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
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.
| Peabody Energy Corporation | 2022 Form 10-K | 60 | ||||||
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 2019, we2022, Peabody produced and sold 164.7122.9 million and 165.5123.7 million tons of coal, respectively, from continuing operations.
As of December 31, 2019, we report our results of operations primarily through2022, the following reportable segments: Seaborne Thermal Mining, Seaborne Metallurgical Mining, Powder River Basin Mining, Midwestern U.S. Mining, Western U.S. Mining and Corporate and Other.
The business of ourthe Company’s seaborne operating platform is primarily export focused with customers spread across several countries, with a portion of ourits thermal and metallurgical coal sold within Australia. Generally, revenuesrevenue from individual countries vary year by year based on electricity and steel demand, the strength of the global economy, governmental policies and several other factors, including those specific to each country. We classify ourThe 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, wethe Company may market some of ourits metallurgical coal products as a thermal coal product from time to time depending on market conditions.
The principal business of ourthe Company’s thermal miningoperating 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. OurThe Company’s Powder River Basin Mining operations consist of ourits mines in Wyoming. The mines in that segment are characterized by surface mining extraction processes, coal with a lower sulfur content and Btu and higher customer transportation costs (due to longer shipping distances). Our MidwesternThe Company’s Other U.S. Thermal Mining operations include ourreflect the aggregation of its Illinois, Indiana, New Mexico and IndianaColorado mining operations, whichoperations. 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). Our Western U.S. Mining operations historically reflectGeologically, the aggregation of our New Mexico, Arizona and Colorado mining operations. The mines in that segment are characterized by a mix of surface and underground mining extraction processes and coal with a mid-range sulfur content and Btu. Geologically, ourCompany’s Powder River Basin Mining operations mine sub-bituminous coal deposits our Midwesternand its Other U.S. Mining operations mine bituminous coal deposits and our Western U.S.Thermal Mining operations mine both bituminous and sub-bituminous coal deposits.
| Peabody Energy Corporation | 2022 Form 10-K | 61 | ||||||
Resource Management. As of December 31, 2019, we2022, Peabody controlled approximately 4.12.4 billion tons of proven and probable coal reserves, 2.4 billion tons of resources and approximately 500,000360,000 acres of surface property through ownership and lease agreements. We haveThe Company has an ongoing asset optimization program whereby ourits 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 we havePeabody has completed post-mining reclamation. In addition, we generatethe Company generates revenue through royalties from coal reserves and oil and gas rights leased to third parties, and farm income from surface lands under third-party contracts.contracts and lease income from surface lands under contracts with renewable energy ventures.
Middlemount Mine. We ownPeabody owns a 50% equity interest in Middlemount, which owns the Middlemount Mine in Queensland, Australia. The mine predominantly produces semi-hard coking coal and LV PCIlow-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, 2019, 20182022 and 2017,2021, the mine sold 2.9 million, 4.21.6 million and 4.22.0 million tons of coal, respectively (on a 100%50% basis).
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.
| High | Low | Average | December 31, 2022 | February 17, 2023 | ||||||||||||||||||||||||||||
Premium HCC (1) | $ | 670.50 | $ | 188.00 | $ | 363.45 | $ | 294.50 | $ | 390.00 | ||||||||||||||||||||||
Premium PCI coal (1) | $ | 655.00 | $ | 180.50 | $ | 330.81 | $ | 284.50 | $ | 344.00 | ||||||||||||||||||||||
Newcastle index thermal coal (1) | $ | 452.81 | $ | 201.54 | $ | 362.78 | $ | 398.50 | $ | 187.27 | ||||||||||||||||||||||
API 5 index thermal coal (1) | $ | 284.20 | $ | 109.66 | $ | 176.44 | $ | 133.38 | $ | 117.72 | ||||||||||||||||||||||
PRB 8,800 Btu/Lb coal (2) | $ | 27.50 | $ | 15.50 | $ | 18.03 | $ | 15.50 | $ | 14.80 | ||||||||||||||||||||||
Illinois Basin 11,500 Btu/Lb coal (2) | $ | 196.00 | $ | 88.00 | $ | 149.32 | $ | 134.00 | $ | 83.00 | ||||||||||||||||||||||
(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.
| Peabody Energy Corporation | ||||||||
In the mineUnited 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 determinecoal 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 causeyear 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 event, assessyear ended December 31, 2022, utility consumption of PRB coal declined approximately 5% compared to the response to it and make recommendations to reduce the possibility of future incidents and improve response.prior year period.
Financing Transactions
During the first quarter of 2019, we completed segmenting2022, Peabody issued convertible senior unsecured notes and used the proceeds of the mine into multiple zonesoffering to facilitate a phased reventilationretire nearer term higher cost senior secured debt. This both lowered the Company’s borrowing rates and re-entry of the mine. We commenced reventilation of the first zone of the mine during the second quarter of 2019extended debt maturities to 2028. Throughout 2022, Peabody continued to reduce its outstanding debt, and subsequently re-entered the area in the third quarter. Following these activities and a detailed review and assessment of North Goonyella, we determined that due to the time, cost and required regulatory approach to ventilate and re-enter the rest of the mine, we will not pursue attempts to access certain portions of the mine through existing mine workings, but instead will move to the southern panels. We are currently in discussions with the QMI regarding ventilation and re-entry of the second zone of the current mine configuration. In 2020, we are commencing a commercial process for North Goonyella in conjunction with the existing mine development. The process comes in response to expressions of interest from potential strategic partners and other producers. Commercial outcomes could include a strategic financial partner, a joint venture structure or the complete sale of North Goonyella. Alternatively, the commercial process could be abandoned in the absence of an acceptable outcome. Based on the success of discussions with QMI and/or progression of the commercial process being launched, we will determine the appropriate level, if any, and timing of capital expenditures. We anticipate annual holding costs of approximately $24 million per year in relation to North Goonyella, excluding $16 million in take-or-pay commitments, which we are in discussions to reduce.
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 in containment and idling costs related to the events at North Goonyella and a provision of $66.4 million for expected equipment losses. As work progressed and more information became available, we recorded an additional $111.5 million in containment and idling costs and an additional provision of $83.2 million related to equipment losses during the year ended December 31, 2019.2022 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 combined provision includes $50.7project 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 estimated costfirst quarter of 2024. Cash flow from operations is expected to replace leased equipment, $45.6 million relatedfund 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 costcurrent approved amount are estimated to be $240 million, with longwall operations expected to commence in 2026.
| Peabody Energy Corporation | 2022 Form 10-K | 63 | ||||||
Other
In March 2019, we2022, 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 insurance claim settlement agreement with our insurers and various re-insurers under a combined property damage and business interruption policyequity 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 $125 million insurance recovery, the maximum amount available under the policy above a $50 million deductible. We have collected the full amountwholly owned subsidiary of the recovery.
Results of Operations
Year Ended December 31, 20192022 Compared to Year Ended December 31, 2018
The seaborne pricing included in the table below is not necessarily indicative of the pricing we realized during the year ended December 31, 2019 due to quality differentials and the majority of our seaborne sales being executed through annual and multi-year international coal supply agreements that contain provisions requiring both parties to renegotiate pricing periodically. Our typical practice is to negotiate pricing for seaborne metallurgical coal contracts on a quarterly, spot or index basis and seaborne thermal coal contracts on an annual, spot or index basis.
| High | Low | Average | December 31, 2019 | |||||||||||||
Premium HCC (1) | $ | 215.80 | $ | 127.30 | $ | 176.66 | $ | 136.10 | ||||||||
Premium PCI coal (1) | $ | 129.85 | $ | 85.50 | $ | 110.50 | $ | 86.65 | ||||||||
Newcastle index thermal coal (1) | $ | 99.78 | $ | 62.32 | $ | 77.74 | $ | 66.55 | ||||||||
API 5 thermal coal (1) | $ | 62.87 | $ | 48.00 | $ | 54.41 | $ | 51.30 | ||||||||
PRB 8,800 Btu/Lb coal (2) | $ | 12.60 | $ | 12.05 | $ | 12.22 | $ | 12.10 | ||||||||
Illinois Basin 11,500 Btu/Lb coal (2) | $ | 47.50 | $ | 33.50 | $ | 38.83 | $ | 33.65 | ||||||||
Tons Sold
The following table presents tons sold by operating segment:
| Successor | Increase (Decrease) | ||||||||||
| Year Ended December 31, | to Volumes | ||||||||||
| 2019 | 2018 | Tons | % | ||||||||
| (Tons in millions) | |||||||||||
| Seaborne Thermal Mining | 19.5 | 19.1 | 0.4 | 2.1 | % | ||||||
| Seaborne Metallurgical Mining | 8.1 | 11.0 | (2.9 | ) | (26.4 | )% | |||||
| Powder River Basin Mining | 108.1 | 120.3 | (12.2 | ) | (10.1 | )% | |||||
| Midwestern U.S. Mining | 16.0 | 18.9 | (2.9 | ) | (15.3 | )% | |||||
| Western U.S. Mining | 11.9 | 14.7 | (2.8 | ) | (19.0 | )% | |||||
| Total tons sold from mining segments | 163.6 | 184.0 | (20.4 | ) | (11.1 | )% | |||||
| Corporate and Other | 1.9 | 2.7 | (0.8 | ) | (29.6 | )% | |||||
| Total tons sold | 165.5 | 186.7 | (21.2 | ) | (11.4 | )% | |||||
| (Decrease) Increase | |||||||||||||||||||||||
| Year Ended December 31, | to Volumes | ||||||||||||||||||||||
| 2022 | 2021 | Tons | % | ||||||||||||||||||||
| (Tons in millions) | |||||||||||||||||||||||
| Seaborne Thermal Mining | 15.6 | 17.3 | (1.7) | (9.8) | % | ||||||||||||||||||
| Seaborne Metallurgical Mining | 6.6 | 5.5 | 1.1 | 20.0 | % | ||||||||||||||||||
| Powder River Basin Mining | 82.6 | 88.4 | (5.8) | (6.6) | % | ||||||||||||||||||
| Other U.S. Thermal Mining | 18.4 | 16.9 | 1.5 | 8.9 | % | ||||||||||||||||||
| Total tons sold from operating segments | 123.2 | 128.1 | (4.9) | (3.8) | % | ||||||||||||||||||
| Corporate and Other | 0.5 | 2.0 | (1.5) | (75.0) | % | ||||||||||||||||||
| Total tons sold | 123.7 | 130.1 | (6.4) | (4.9) | % | ||||||||||||||||||
| Peabody Energy Corporation | ||||||||
Supplemental Financial Data
The following table presents supplemental financial data by operating segment:
| Year Ended December 31, | Increase (Decrease) | ||||||||||||||||||||||
| 2022 | 2021 | $ | % | ||||||||||||||||||||
Revenue per Ton - Mining Operations (1) | |||||||||||||||||||||||
| Seaborne Thermal | $ | 86.07 | $ | 54.09 | $ | 31.98 | 59.1 | % | |||||||||||||||
| Seaborne Metallurgical | 243.78 | 131.83 | 111.95 | 84.9 | % | ||||||||||||||||||
| Powder River Basin | 12.89 | 10.99 | 1.90 | 17.3 | % | ||||||||||||||||||
| Other U.S. Thermal | 51.82 | 40.75 | 11.07 | 27.2 | % | ||||||||||||||||||
Costs per Ton - Mining Operations (1) (2) | |||||||||||||||||||||||
| Seaborne Thermal | $ | 44.65 | $ | 33.64 | $ | 11.01 | 32.7 | % | |||||||||||||||
| Seaborne Metallurgical | 125.92 | 99.55 | 26.37 | 26.5 | % | ||||||||||||||||||
| Powder River Basin | 12.06 | 9.46 | 2.60 | 27.5 | % | ||||||||||||||||||
| Other U.S. Thermal | 38.63 | 31.04 | 7.59 | 24.5 | % | ||||||||||||||||||
Adjusted EBITDA Margin per Ton - Mining Operations (1) (2) | |||||||||||||||||||||||
| Seaborne Thermal | $ | 41.42 | $ | 20.45 | $ | 20.97 | 102.5 | % | |||||||||||||||
| Seaborne Metallurgical | 117.86 | 32.28 | 85.58 | 265.1 | % | ||||||||||||||||||
| Powder River Basin | 0.83 | 1.53 | (0.70) | (45.8) | % | ||||||||||||||||||
| Other U.S. Thermal | 13.19 | 9.71 | 3.48 | 35.8 | % | ||||||||||||||||||
| Successor | ||||||||||||||
| Year Ended December 31, | (Decrease) Increase | |||||||||||||
| 2019 | 2018 | $ | % | |||||||||||
Revenues per Ton - Mining Operations (1) | ||||||||||||||
| Seaborne Thermal | $ | 49.69 | $ | 57.58 | $ | (7.89 | ) | (13.7 | )% | |||||
| Seaborne Metallurgical | 127.62 | 141.06 | (13.44 | ) | (9.5 | )% | ||||||||
| Powder River Basin | 11.37 | 11.84 | (0.47 | ) | (4.0 | )% | ||||||||
| Midwestern U.S. | 41.90 | 42.44 | (0.54 | ) | (1.3 | )% | ||||||||
| Western U.S. | 53.48 | 40.20 | 13.28 | 33.0 | % | |||||||||
Costs per Ton - Mining Operations (1) (2) | ||||||||||||||
| Seaborne Thermal | $ | 32.84 | $ | 33.90 | $ | (1.06 | ) | (3.1 | )% | |||||
Seaborne Metallurgical (3) | 110.30 | 100.97 | 9.33 | 9.2 | % | |||||||||
| Powder River Basin | 9.32 | 9.47 | (0.15 | ) | (1.6 | )% | ||||||||
| Midwestern U.S. | 33.72 | 34.75 | (1.03 | ) | (3.0 | )% | ||||||||
| Western U.S. | 34.19 | 30.33 | 3.86 | 12.7 | % | |||||||||
Adjusted EBITDA Margin per Ton - Mining Operations (1) (2) | ||||||||||||||
| Seaborne Thermal | $ | 16.85 | $ | 23.68 | $ | (6.83 | ) | (28.8 | )% | |||||
Seaborne Metallurgical (3) | 17.32 | 40.09 | (22.77 | ) | (56.8 | )% | ||||||||
| Powder River Basin | 2.05 | 2.37 | (0.32 | ) | (13.5 | )% | ||||||||
| Midwestern U.S. | 8.18 | 7.69 | 0.49 | 6.4 | % | |||||||||
| Western U.S. | 19.29 | 9.87 | 9.42 | 95.4 | % | |||||||||
Revenue
The following table presents revenuesrevenue by reporting segment:
| Successor | (Decrease) Increase | Increase | |||||||||||||||||||||||||||||||||||
| Year Ended December 31, | to Revenues | Year Ended December 31, | to Revenue | ||||||||||||||||||||||||||||||||||
| 2019 | 2018 | $ | % | 2022 | 2021 | $ | % | ||||||||||||||||||||||||||||||
| (Dollars in millions) | (Dollars in millions) | ||||||||||||||||||||||||||||||||||||
| Seaborne Thermal Mining | $ | 971.7 | $ | 1,099.2 | $ | (127.5 | ) | (11.6 | )% | Seaborne Thermal Mining | $ | 1,345.6 | $ | 934.0 | $ | 411.6 | 44.1 | % | |||||||||||||||||||
| Seaborne Metallurgical Mining | 1,033.1 | 1,553.0 | (519.9 | ) | (33.5 | )% | Seaborne Metallurgical Mining | 1,616.9 | 727.7 | 889.2 | 122.2 | % | |||||||||||||||||||||||||
| Powder River Basin Mining | 1,228.7 | 1,424.8 | (196.1 | ) | (13.8 | )% | Powder River Basin Mining | 1,065.5 | 971.2 | 94.3 | 9.7 | % | |||||||||||||||||||||||||
| Midwestern U.S. Mining | 669.7 | 801.0 | (131.3 | ) | (16.4 | )% | |||||||||||||||||||||||||||||||
| Western U.S. Mining | 639.7 | 592.0 | 47.7 | 8.1 | % | ||||||||||||||||||||||||||||||||
| Other U.S. Thermal Mining | Other U.S. Thermal Mining | 952.2 | 689.1 | 263.1 | 38.2 | % | |||||||||||||||||||||||||||||||
| Corporate and Other | 80.5 | 111.8 | (31.3 | ) | (28.0 | )% | Corporate and Other | 1.7 | (3.7) | 5.4 | 145.9 | % | |||||||||||||||||||||||||
| Revenues | $ | 4,623.4 | $ | 5,581.8 | $ | (958.4 | ) | (17.2 | )% | ||||||||||||||||||||||||||||
| Revenue | Revenue | $ | 4,981.9 | $ | 3,318.3 | $ | 1,663.6 | 50.1 | % | ||||||||||||||||||||||||||||
Seaborne Thermal Mining. The decreaseincrease in our Seaborne Thermal Mining segment revenues forrevenue during the year ended December 31, 20192022 compared to the prior year was primarily driven by unfavorabledue to favorable realized coal pricingprices ($131.9540.4 million), partially offset by favorable volumeunfavorable volumes ($128.8 million) which were impacted by wet weather in the current year and mix variances ($4.4 million).
Seaborne Metallurgical Mining. Segment revenues decreasedrevenue increased during the year ended December 31, 20192022 compared to the same period in the prior year primarily due to unfavorable volumes (2.9 million tons, $441.1favorable realized prices at the Australian operations ($583.1 million). The unfavorable volume variance resulting from, the transition to highwall miningresumption of sales at our Millennium Mine in September 2018, an extended longwall move at our Metropolitan Mine and various mine sequencing impacts (3.2 million tons, $424.4 million) and no current year volume from our North Goonyella Mine (1.7 million tons, $337.6 million) was partially offset by incremental volume provided by ourthe Shoal Creek Mine acquired in December 2018 (2.0 million tons, $320.9($236.6 million) and favorable volume and mix variances at the Australian operations ($69.5 million). Segment revenues were further impactedSales volumes increased by lower realized pricing ($78.8 million).20% from the prior year.
Powder River Basin Mining. Segment revenues decreased during the year ended December 31, 2019 compared to the same period in the prior year due to lower volume primarily attributable to lower demand and railroad closures and delays that resulted from severe flooding across the upper Great Plains during the first half of 2019 ($157.9 million) and unfavorable realized pricing ($57.9 million). These unfavorable variances were partially offset by a favorable contract settlement with a PRB customer ($19.7 million).
| Peabody Energy Corporation | 2022 Form 10-K | 65 | ||||||
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 unfavorable realized pricingfavorable volumes ($4.453.9 million).
Corporate and Other. Segment revenues decreasedrevenue increased during the year ended December 31, 20192022 compared to the same period in the prior year primarily 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 economic hedges.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 ourthe Company’s reporting segments:
| Increase (Decrease) to | |||||||||||||||||||||||
| Year Ended December 31, | Adjusted EBITDA | ||||||||||||||||||||||
| 2022 | 2021 | $ | % | ||||||||||||||||||||
| (Dollars in millions) | |||||||||||||||||||||||
| Seaborne Thermal Mining | $ | 647.6 | $ | 353.1 | $ | 294.5 | 83.4 | % | |||||||||||||||
| Seaborne Metallurgical Mining | 781.7 | 178.2 | 603.5 | 338.7 | % | ||||||||||||||||||
| Powder River Basin Mining | 68.2 | 134.9 | (66.7) | (49.4) | % | ||||||||||||||||||
| Other U.S. Thermal Mining | 242.4 | 164.2 | 78.2 | 47.6 | % | ||||||||||||||||||
| Corporate and Other | 104.8 | 86.3 | 18.5 | 21.4 | % | ||||||||||||||||||
Adjusted EBITDA (1) | $ | 1,844.7 | $ | 916.7 | $ | 928.0 | 101.2 | % | |||||||||||||||
| Successor | (Decrease) Increase to | |||||||||||||
| Year Ended December 31, | Adjusted EBITDA | |||||||||||||
| 2019 | 2018 | $ | % | |||||||||||
| (Dollars in millions) | ||||||||||||||
| Seaborne Thermal Mining | $ | 329.4 | $ | 452.0 | $ | (122.6 | ) | (27.1 | )% | |||||
| Seaborne Metallurgical Mining | 140.2 | 441.4 | (301.2 | ) | (68.2 | )% | ||||||||
| Powder River Basin Mining | 221.2 | 284.5 | (63.3 | ) | (22.2 | )% | ||||||||
| Midwestern U.S. Mining | 130.7 | 145.2 | (14.5 | ) | (10.0 | )% | ||||||||
| Western U.S. Mining | 230.7 | 145.4 | 85.3 | 58.7 | % | |||||||||
| Corporate and Other | (215.1 | ) | (89.2 | ) | (125.9 | ) | (141.1 | )% | ||||||
Adjusted EBITDA (1) | $ | 837.1 | $ | 1,379.3 | $ | (542.2 | ) | (39.3 | )% | |||||
Seaborne Thermal Mining. Segment Adjusted EBITDA decreasedincreased during the year ended December 31, 20192022 compared to the same period in the prior year as a result of lowerhigher realized prices net coal pricingof sales sensitive costs ($121.7 million) and unfavorable mine sequencing impacts and higher equipment maintenance costs among our thermal surface mines ($48.1 million), offset by improved longwall performance at our Wambo Underground Mine ($30.2495.5 million) and favorable foreign currency impacts ($24.125.2 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 decreasedincreased during the year ended December 31, 20192022 compared to the same period in the prior year due to unfavorable volume variances described abovehigher realized prices net of sales sensitive costs at the Australian operations ($231.9466.9 million). The impact, favorable volumes from the resumption of the negative volumessales at our Australian mines ($356.8 million) was partially offset by the incremental volume provided by our Shoal Creek Mine ($124.9 million). The decrease in Segment Adjusted EBITDA was further impacted by lower realized net coal pricing ($71.6 million), mine sequencing impacts among our metallurgical surface operations ($62.6111.6 million) and the net containment and holding costs at our North Goonyella Mine ($19.6 million). These negative variances were partially offset by favorable foreign currency impacts ($50.536.3 million).
Powder River Basin Mining. Segment Adjusted EBITDA decreased during the year ended December 31, 20192022 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 the impacthigher realized prices net of lower volumesales sensitive costs ($78.7 million) described above, lower realized net coal pricing ($10.7210.4 million) and unfavorable mine sequencing impactsfavorable volumes ($10.019.2 million), partially. These increases were offset by the net impact of the favorable contract settlement with a PRB customer ($24.0 million) and lower lease expenses due to early lease buyouts ($8.6 million).
| Peabody Energy Corporation | 2022 Form 10-K | 66 | ||||||
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 | ||||||||||||||||||||||
| 2022 | 2021 | $ | % | ||||||||||||||||||||
| (Dollars in millions) | |||||||||||||||||||||||
Middlemount (1) | $ | 132.8 | $ | 48.2 | $ | 84.6 | 175.5 | % | |||||||||||||||
Resource management activities (2) | 29.3 | 6.9 | 22.4 | 324.6 | % | ||||||||||||||||||
| Selling and administrative expenses | (88.8) | (84.9) | (3.9) | (4.6) | % | ||||||||||||||||||
Other items, net (3) | 31.5 | 116.1 | (84.6) | (72.9) | % | ||||||||||||||||||
| Corporate and Other Adjusted EBITDA | $ | 104.8 | $ | 86.3 | $ | 18.5 | 21.4 | % | |||||||||||||||
| Successor | (Decrease) Increase | |||||||||||||
| Year Ended December 31, | to Income | |||||||||||||
| 2019 | 2018 | $ | % | |||||||||||
| (Dollars in millions) | ||||||||||||||
Middlemount (1) | $ | (9.8 | ) | $ | 51.1 | $ | (60.9 | ) | (119.2 | )% | ||||
Resource management activities (2) | 8.2 | 44.7 | (36.5 | ) | (81.7 | )% | ||||||||
| Selling and administrative expenses | (145.0 | ) | (158.1 | ) | 13.1 | 8.3 | % | |||||||
| Restructuring charges | (24.3 | ) | (1.2 | ) | (23.1 | ) | (1,925.0 | )% | ||||||
| Transaction costs related to business combinations and joint ventures | (21.6 | ) | (7.4 | ) | (14.2 | ) | (191.9 | )% | ||||||
Other items, net (3) | (22.6 | ) | (18.3 | ) | (4.3 | ) | (23.5 | )% | ||||||
| Corporate and Other Adjusted EBITDA | $ | (215.1 | ) | $ | (89.2 | ) | $ | (125.9 | ) | (141.1 | )% | |||
(1) | Middlemount’s results are before the impact of related changes |
(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, 20192022 compared to the same period in the prior year was primarily driven by an unfavorable variancefrom favorable variances in Middlemount’s results due to the temporary suspensionimpact of operationshigher 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 significant change to the mine plan following a highwall failure mid-2019; resource management gains recordedgain recognized in the prior year period related toon the sale of surplus land assets in Queensland’s Bowen Basin ($20.6 million) and the sale of surplus coal resources associated with theCompany’s Millennium Mine ($20.526.1 million); restructuring charges recorded as discussed in the current year for workforce reductions resulting from actions taken at the the North Goonyella Mine, U.S. mine closures and reductions in overhead and support functions; and increased transaction costs in the current year period related to the PRB Colorado joint venture with Arch. These unfavorable results were partially offset by lower selling and administrative expenses primarily related to outside services and incentive compensation.Note 17. “Other Events.”
The following table presents (loss) income from continuing operations, net of income taxes:
| Increase (Decrease) to Income | |||||||||||||||||||||||
| Year Ended December 31, | |||||||||||||||||||||||
| 2022 | 2021 | $ | % | ||||||||||||||||||||
| (Dollars in millions) | |||||||||||||||||||||||
Adjusted EBITDA (1) | $ | 1,844.7 | $ | 916.7 | $ | 928.0 | 101.2 | % | |||||||||||||||
| Depreciation, depletion and amortization | (317.6) | (308.7) | (8.9) | (2.9) | % | ||||||||||||||||||
| Asset retirement obligation expenses | (49.4) | (44.7) | (4.7) | (10.5) | % | ||||||||||||||||||
| Restructuring charges | (2.9) | (8.3) | 5.4 | 65.1 | % | ||||||||||||||||||
| Asset impairment | (11.2) | — | (11.2) | n.m. | |||||||||||||||||||
| Changes in deferred tax asset valuation allowance and reserves and amortization of basis difference related to equity affiliates | 2.3 | 33.8 | (31.5) | (93.2) | % | ||||||||||||||||||
| Interest expense | (140.3) | (183.4) | 43.1 | 23.5 | % | ||||||||||||||||||
| Net (loss) gain on early debt extinguishment | (57.9) | 33.2 | (91.1) | (274.4) | % | ||||||||||||||||||
| Interest income | 18.4 | 6.5 | 11.9 | 183.1 | % | ||||||||||||||||||
| Net mark-to-market adjustment on actuarially determined liabilities | 27.8 | 43.4 | (15.6) | (35.9) | % | ||||||||||||||||||
| Unrealized losses on derivative contracts related to forecasted sales | (35.8) | (115.1) | 79.3 | 68.9 | % | ||||||||||||||||||
| 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) | % | ||||||||||||||||||
| Income tax benefit (provision) | 38.8 | (22.8) | 61.6 | 270.2 | % | ||||||||||||||||||
| Income from continuing operations, net of income taxes | $ | 1,317.4 | $ | 347.4 | $ | 970.0 | 279.2 | % | |||||||||||||||
(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.
| Successor | (Decrease) Increase to Income | |||||||||||||
| Year Ended December 31, | ||||||||||||||
| 2019 | 2018 | $ | % | |||||||||||
| (Dollars in millions) | ||||||||||||||
Adjusted EBITDA (1) | $ | 837.1 | $ | 1,379.3 | $ | (542.2 | ) | (39.3 | )% | |||||
| Depreciation, depletion and amortization | (601.0 | ) | (679.0 | ) | 78.0 | 11.5 | % | |||||||
| Asset retirement obligation expenses | (58.4 | ) | (53.0 | ) | (5.4 | ) | (10.2 | )% | ||||||
| Gain on formation of United Wambo Joint Venture | 48.1 | — | 48.1 | n.m. | ||||||||||
| Asset impairment | (270.2 | ) | — | (270.2 | ) | n.m. | ||||||||
| Provision for North Goonyella equipment loss | (83.2 | ) | (66.4 | ) | (16.8 | ) | (25.3 | )% | ||||||
| North Goonyella insurance recovery - equipment | 91.1 | — | 91.1 | n.m. | ||||||||||
| Changes in deferred tax asset valuation allowance and reserves and amortization of basis difference related to equity affiliates | 18.8 | 18.3 | 0.5 | 2.7 | % | |||||||||
| Interest expense | (144.0 | ) | (149.3 | ) | 5.3 | 3.5 | % | |||||||
| Loss on early debt extinguishment | (0.2 | ) | (2.0 | ) | 1.8 | 90.0 | % | |||||||
| Interest income | 27.0 | 33.6 | (6.6 | ) | (19.6 | )% | ||||||||
| Net mark-to-market adjustment on actuarially determined liabilities | (67.4 | ) | 125.5 | (192.9 | ) | (153.7 | )% | |||||||
| Reorganization items, net | — | 12.8 | (12.8 | ) | (100.0 | )% | ||||||||
| Unrealized gains on economic hedges | 42.2 | 18.3 | 23.9 | 130.6 | % | |||||||||
| Unrealized gains (losses) on non-coal trading derivative contracts | 1.2 | (0.7 | ) | 1.9 | 271.4 | % | ||||||||
| Fresh start take-or-pay contract-based intangible recognition | 16.6 | 26.7 | (10.1 | ) | (37.8 | )% | ||||||||
| Income tax provision | (46.0 | ) | (18.4 | ) | (27.6 | ) | (150.0 | )% | ||||||
| (Loss) income from continuing operations, net of income taxes | $ | (188.3 | ) | $ | 645.7 | $ | (834.0 | ) | (129.2 | )% | ||||
| 67 | ||||||||
Depreciation, Depletion and Amortization. The following table presents a summary of depreciation, depletion and amortization expense by reporting segment:
| Successor | (Decrease) Increase | |||||||||||||
| Year Ended December 31, | to Income | |||||||||||||
| 2019 | 2018 | $ | % | |||||||||||
| (Dollars in millions) | ||||||||||||||
| Seaborne Thermal Mining | $ | (90.7 | ) | $ | (88.4 | ) | $ | (2.3 | ) | (2.6 | )% | |||
| Seaborne Metallurgical Mining | (125.3 | ) | (129.8 | ) | 4.5 | 3.5 | % | |||||||
| Powder River Basin Mining | (148.5 | ) | (183.4 | ) | 34.9 | 19.0 | % | |||||||
| Midwestern U.S. Mining | (94.1 | ) | (121.5 | ) | 27.4 | 22.6 | % | |||||||
| Western U.S. Mining | (134.1 | ) | (147.3 | ) | 13.2 | 9.0 | % | |||||||
| Corporate and Other | (8.3 | ) | (8.6 | ) | 0.3 | 3.5 | % | |||||||
| Total | $ | (601.0 | ) | $ | (679.0 | ) | $ | 78.0 | 11.5 | % | ||||
| (Decrease) Increase | |||||||||||||||||||||||
| Year Ended December 31, | to Income | ||||||||||||||||||||||
| 2022 | 2021 | $ | % | ||||||||||||||||||||
| (Dollars in millions) | |||||||||||||||||||||||
| Seaborne Thermal Mining | $ | (114.4) | $ | (107.7) | $ | (6.7) | (6.2) | % | |||||||||||||||
| Seaborne Metallurgical Mining | (88.8) | (73.3) | (15.5) | (21.1) | % | ||||||||||||||||||
| Powder River Basin Mining | (42.5) | (41.5) | (1.0) | (2.4) | % | ||||||||||||||||||
| Other U.S. Thermal Mining | (62.2) | (67.4) | 5.2 | 7.7 | % | ||||||||||||||||||
| Corporate and Other | (9.7) | (18.8) | 9.1 | 48.4 | % | ||||||||||||||||||
| Total | $ | (317.6) | $ | (308.7) | $ | (8.9) | (2.9) | % | |||||||||||||||
Additionally, the following table presents a summary of ourthe Company’s weighted-average depletion rate per ton for active mines in each of our miningits operating segments:
| Year Ended December 31, | |||||||||||
| 2022 | 2021 | ||||||||||
| 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 | |||||||||
| Successor | |||||||
| Year Ended December 31, | |||||||
| 2019 | 2018 | ||||||
| Seaborne Thermal Mining | $ | 1.84 | $ | 1.79 | |||
| Seaborne Metallurgical Mining | 3.09 | 0.94 | |||||
| Powder River Basin Mining | 0.80 | 0.81 | |||||
| Midwestern U.S. Mining | 1.05 | 0.89 | |||||
| Western U.S. Mining | 1.72 | 2.29 | |||||
Asset Impairment. WeThe Company recognized $270.2$11.2 million in aggregate asset impairment charges during the year ended December 31, 2019.2022 related to the sale of certain land interests and an investment in equity securities. Refer to Note 5.3. “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.
Interest Expense. The decrease in interest expense during the year ended December 31, 2022 compared to total equipment losses recognized at the timeprior 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 insurance recovery settlement, which consistedCompany 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 $24.7 million and $66.4 million recognizedexisting notes during the years ended December 31, 20192022 and 2018, respectively. The remaining $33.9 million, applicable2021, as further discussed in Note 10. “Long-term Debt” to incremental costs and business interruption losses, is included in Adjusted EBITDA for the year ended December 31, 2019.accompanying consolidated financial statements.
Interest Income. The decreaseincrease in interest income during the year ended December 31, 2019 as2022 compared to the prior year was driven by lowerprimarily due to higher cash balances.balances and interest rates in the current year.
| Peabody Energy Corporation | 2022 Form 10-K | 68 | ||||||
Net Mark-to-Market Adjustment on Actuarially Determined Liabilities. The expensegain recorded during the year ended December 31, 20192022 was driven by decreasesincreases to the discount rates for all actuarially determined liabilities ($137.6190.1 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 impactimpacts of changes related to claims and an update to our census datamedical trend updates for the postretirement benefitsbenefit plans ($19.7 million). These decreases were partially offset by actuarial gains on pension assets ($94.515.7 million).
The gain recorded during the year ended December 31, 20182021 was driven by increases to the discount rates for actuarially determined liabilities ($46.237.6 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 changes related to claims ($54.2 million), updates to the Medicare law ($20.0 million) and an update to ourthe Company’s census data ($7.7 million) for the postretirement benefit plans. The impact on our pension plans was small as actuarialactuarially determined liabilities ($10.3 million). These increases were offset by mark-to-market losses on pension and postretirement benefit plan assets were largely offset by an increase in discount rates.
Unrealized GainsLosses on Economic Hedges.Derivative Contracts Related to Forecasted Sales. Unrealized gainslosses primarily relate to mark-to-market activity from economic hedge activities intendedon derivative contracts related to hedge futureforecasted coal sales. For additional information, refer to Note 9.6. “Derivatives and Fair Value Measurements” to the accompanying consolidated financial statements.
Income Tax ProvisionBenefit (Provision). The increase in the income tax provisionbenefit recorded during the year ended December 31, 2019 as compared to the prior year period2022 was primarily related to the tax impact of the gain on formation of the United Wambo Joint Venture recognized during the fourth quarter of 2019, the year-over-year change in the benefit recorded in continuing operations under the exception provisions within ASC 740-20-45-7 and the prior year tax benefit relateddue to the release of valuation allowance on refundable alternative minimum tax credits .related to Australian NOLs, partially offset by year-over-year increases in pretax income. Refer to Note 12.8. “Income Taxes” to the accompanying consolidated financial statements for additional information.
Net (Loss) Income Attributable to Common Stockholders
The following table presents net (loss) income attributable to common stockholders:
| Successor | (Decrease) Increase to | |||||||||||||
| Year Ended December 31, | to Income | |||||||||||||
| 2019 | 2018 | $ | % | |||||||||||
| (Dollars in millions) | ||||||||||||||
| (Loss) income from continuing operations, net of income taxes | $ | (188.3 | ) | $ | 645.7 | $ | (834.0 | ) | (129.2 | )% | ||||
| Income from discontinued operations, net of income taxes | 3.2 | 18.1 | (14.9 | ) | (82.3 | )% | ||||||||
| Net (loss) income | (185.1 | ) | 663.8 | (848.9 | ) | (127.9 | )% | |||||||
| Less: Series A Convertible Preferred Stock dividends | — | 102.5 | (102.5 | ) | (100.0 | )% | ||||||||
| Less: Net income attributable to noncontrolling interests | 26.2 | 16.9 | 9.3 | 55.0 | % | |||||||||
| Net (loss) income attributable to common stockholders | $ | (211.3 | ) | $ | 544.4 | $ | (755.7 | ) | (138.8 | )% | ||||
| Increase (Decrease) | |||||||||||||||||||||||
| Year Ended December 31, | to Income | ||||||||||||||||||||||
| 2022 | 2021 | $ | % | ||||||||||||||||||||
| (Dollars in millions) | |||||||||||||||||||||||
| Income from continuing operations, net of income taxes | $ | 1,317.4 | $ | 347.4 | $ | 970.0 | 279.2 | % | |||||||||||||||
| Income from discontinued operations, net of income taxes | 1.7 | 24.0 | (22.3) | (92.9) | % | ||||||||||||||||||
| Net income | 1,319.1 | 371.4 | 947.7 | 255.2 | % | ||||||||||||||||||
| Less: Net income attributable to noncontrolling interests | 22.0 | 11.3 | 10.7 | 94.7 | % | ||||||||||||||||||
| Net income attributable to common stockholders | $ | 1,297.1 | $ | 360.1 | $ | 937.0 | 260.2 | % | |||||||||||||||
Income from Discontinued Operations, Net of Income Taxes. The decrease in income from discontinued operations, net of income taxes during the year ended December 31, 2019 as2022 compared to the prior year period was primarily driven by smaller actuarial gains associated with black lung liabilities.
Net Income Attributable to Noncontrolling Interests. The increase in net income attributable to noncontrolling interests during the year ended December 31, 20192022 compared to the prior year period was primarily driven by the gain on formationdue to stronger financial results of the United Wambo Joint Venture recognized during the fourth quarter of 2019.Peabody’s majority-owned mines in which there is an outside non-controlling interest.
Diluted EPS
The following table presents diluted EPS:
| Increase (Decrease) to | |||||||||||||||||||||||
| Year Ended December 31, | EPS | ||||||||||||||||||||||
| 2022 | 2021 | $ | % | ||||||||||||||||||||
| Diluted EPS attributable to common stockholders: | |||||||||||||||||||||||
| Income from continuing operations | $ | 8.29 | $ | 3.00 | $ | 5.29 | 176.3 | % | |||||||||||||||
| Income from discontinued operations | 0.02 | 0.22 | (0.20) | (90.9) | % | ||||||||||||||||||
| Net income attributable to common stockholders | $ | 8.31 | $ | 3.22 | $ | 5.09 | 158.1 | % | |||||||||||||||
| Successor | Decrease to | |||||||||||||
| Year Ended December 31, | EPS | |||||||||||||
| 2019 | 2018 | $ | % | |||||||||||
| Diluted EPS attributable to common stockholders: | ||||||||||||||
| (Loss) income from continuing operations | $ | (2.07 | ) | $ | 4.28 | $ | (6.35 | ) | (148.4 | )% | ||||
| Income from discontinued operations | 0.03 | 0.15 | (0.12 | ) | (80.0 | )% | ||||||||
| Net (loss) income attributable to common stockholders | $ | (2.04 | ) | $ | 4.43 | $ | (6.47 | ) | (146.0 | )% | ||||
| Peabody Energy Corporation | 2022 Form 10-K | 69 | ||||||
Diluted EPS is commensurate with the changes in results from continuing operations and discontinued operations during that period. Diluted EPS reflects weighted average diluted common shares outstanding of 103.7157.2 million and 121.0112.0 million for the years ended December 31, 20192022 and 2018,2021, respectively.
Reconciliation of Non-GAAP Financial Measures
Adjusted EBITDA is defined as (loss) income from continuing operations before deducting net interest expense, income taxes, asset retirement obligation expenses and depreciation, depletion and amortization and reorganization items, net.amortization. Adjusted EBITDA is also adjusted for the discrete items that management excluded in analyzing each of ourits segment’s operating performance, as displayed in the reconciliations below.
| Year Ended December 31, | |||||||||||||||||
| 2022 | 2021 | ||||||||||||||||
| (Dollars in millions) | |||||||||||||||||
| Income from continuing operations, net of income taxes | $ | 1,317.4 | $ | 347.4 | |||||||||||||
| Depreciation, depletion and amortization | 317.6 | 308.7 | |||||||||||||||
| Asset retirement obligation expenses | 49.4 | 44.7 | |||||||||||||||
| Restructuring charges | 2.9 | 8.3 | |||||||||||||||
| Asset impairment | 11.2 | — | |||||||||||||||
| Changes in deferred tax asset valuation allowance and reserves and amortization of basis difference related to equity affiliates | (2.3) | (33.8) | |||||||||||||||
| Interest expense | 140.3 | 183.4 | |||||||||||||||
| Net loss (gain) on early debt extinguishment | 57.9 | (33.2) | |||||||||||||||
| Interest income | (18.4) | (6.5) | |||||||||||||||
| Net mark-to-market adjustment on actuarially determined liabilities | (27.8) | (43.4) | |||||||||||||||
| Unrealized losses on derivative contracts related to forecasted sales | 35.8 | 115.1 | |||||||||||||||
| Unrealized losses on foreign currency option contracts | 2.3 | 7.5 | |||||||||||||||
| Take-or-pay contract-based intangible recognition | (2.8) | (4.3) | |||||||||||||||
| Income tax (benefit) provision | (38.8) | 22.8 | |||||||||||||||
| Adjusted EBITDA | $ | 1,844.7 | $ | 916.7 | |||||||||||||
Total Reporting Segment Costs is defined as operating costs and expenses adjusted for the discrete items that management excluded in analyzing each of its segments’ operating performance, as displayed in the reconciliations below:
| Year Ended December 31, | |||||||||||||||||||||||
| 2022 | 2021 | ||||||||||||||||||||||
| (Dollars in millions) | |||||||||||||||||||||||
| Operating costs and expenses | $ | 3,290.8 | $ | 2,553.1 | |||||||||||||||||||
| Unrealized losses on foreign currency option contracts | (2.3) | (7.5) | |||||||||||||||||||||
| Take-or-pay contract-based intangible recognition | 2.8 | 4.3 | |||||||||||||||||||||
| Net periodic benefit credit, excluding service cost | (49.0) | (38.3) | |||||||||||||||||||||
| Total Reporting Segment Costs | $ | 3,242.3 | $ | 2,511.6 | |||||||||||||||||||
The following table presents Total Reporting Segment Costs by reporting segment:
| Year Ended December 31, | |||||||||||||||||
| 2022 | 2021 | ||||||||||||||||
| (Dollars in millions) | |||||||||||||||||
| Seaborne Thermal Mining | $ | 698.0 | $ | 580.9 | |||||||||||||
| Seaborne Metallurgical Mining | 835.2 | 549.5 | |||||||||||||||
| Powder River Basin Mining | 997.3 | 836.3 | |||||||||||||||
| Other U.S. Thermal Mining | 709.8 | 524.9 | |||||||||||||||
| Corporate and Other | 2.0 | 20.0 | |||||||||||||||
| Total Reporting Segment Costs | $ | 3,242.3 | $ | 2,511.6 | |||||||||||||
| Successor | |||||||
| Year Ended December 31, | |||||||
| 2019 | 2018 | ||||||
| (Dollars in millions) | |||||||
| (Loss) income from continuing operations, net of income taxes | $ | (188.3 | ) | $ | 645.7 | ||
| Depreciation, depletion and amortization | 601.0 | 679.0 | |||||
| Asset retirement obligation expenses | 58.4 | 53.0 | |||||
| Gain on formation of United Wambo Joint Venture | (48.1 | ) | — | ||||
| Asset impairment | 270.2 | — | |||||
| Provision for North Goonyella equipment loss | 83.2 | 66.4 | |||||
| North Goonyella insurance recovery - equipment | (91.1 | ) | — | ||||
| Changes in deferred tax asset valuation allowance and reserves and amortization of basis difference related to equity affiliates | (18.8 | ) | (18.3 | ) | |||
| Interest expense | 144.0 | 149.3 | |||||
| Loss on early debt extinguishment | 0.2 | 2.0 | |||||
| Interest income | (27.0 | ) | (33.6 | ) | |||
| Net mark-to-market adjustment on actuarially determined liabilities | 67.4 | (125.5 | ) | ||||
| Reorganization items, net | — | (12.8 | ) | ||||
| Unrealized gains on economic hedges | (42.2 | ) | (18.3 | ) | |||
| Unrealized (gains) losses on non-coal trading derivative contracts | (1.2 | ) | 0.7 | ||||
| Fresh start take-or-pay contract-based intangible recognition | (16.6 | ) | (26.7 | ) | |||
| Income tax provision | 46.0 | 18.4 | |||||
| Adjusted EBITDA | $ | 837.1 | $ | 1,379.3 | |||
| Peabody Energy Corporation | 2022 Form 10-K | 70 | ||||||
Revenue per Ton and Adjusted EBITDA Margin per Ton are equal to revenuesrevenue by segment and Adjusted EBITDA by segment, respectively, divided by segment tons sold. Costs per Ton is equal to RevenuesRevenue per Ton less Adjusted EBITDA Margin per Ton, and are reconciled to operating costs and expenses as follows:
| Successor | |||||||
| Year Ended December 31, | |||||||
| 2019 | 2018 | ||||||
| (Dollars in millions) | |||||||
| Operating costs and expenses | $ | 3,536.6 | $ | 4,071.4 | |||
| Unrealized gains (losses) on non-coal trading derivative contracts | 1.2 | (0.7 | ) | ||||
| Fresh start take-or-pay contract-based intangible recognition | 16.6 | 26.7 | |||||
| North Goonyella insurance recovery - cost recovery and business interruption | (33.9 | ) | — | ||||
| Net periodic benefit costs, excluding service cost | 19.4 | 18.1 | |||||
| Restructuring charges | 24.3 | 1.2 | |||||
| Total Reporting Segment Costs | $ | 3,564.2 | $ | 4,116.7 | |||
| Successor | |||||||
| Year Ended December 31, | |||||||
| 2019 | 2018 | ||||||
| (Dollars in millions) | |||||||
| Seaborne Thermal Mining | $ | 642.3 | $ | 647.2 | |||
| Seaborne Metallurgical Mining | 892.9 | 1,111.6 | |||||
| Powder River Basin Mining | 1,007.5 | 1,140.3 | |||||
| Midwestern U.S. Mining | 539.0 | 655.8 | |||||
| Western U.S. Mining | 409.0 | 446.6 | |||||
| Corporate and Other | 73.5 | 115.2 | |||||
| Total Reporting Segment Costs | $ | 3,564.2 | $ | 4,116.7 | |||
The following tables present tons sold, revenues,revenue, Total Reporting Segment Costs and Adjusted EBITDA by reportingoperating segment:
| Year Ended December 31, 2022 | |||||||||||||||||||||||
| Seaborne Thermal Mining | Seaborne Metallurgical Mining | Powder River Basin Mining | Other U.S. Thermal Mining | ||||||||||||||||||||
| (Amounts in millions, except per ton data) | |||||||||||||||||||||||
| Tons sold | 15.6 | 6.6 | 82.6 | 18.4 | |||||||||||||||||||
| Revenue | $ | 1,345.6 | $ | 1,616.9 | $ | 1,065.5 | $ | 952.2 | |||||||||||||||
| Total Reporting Segment Costs | 698.0 | 835.2 | 997.3 | 709.8 | |||||||||||||||||||
| Adjusted EBITDA | $ | 647.6 | $ | 781.7 | $ | 68.2 | $ | 242.4 | |||||||||||||||
| Revenue per Ton | $ | 86.07 | $ | 243.78 | $ | 12.89 | $ | 51.82 | |||||||||||||||
| Costs per Ton | 44.65 | 125.92 | 12.06 | 38.63 | |||||||||||||||||||
| Adjusted EBITDA Margin per Ton | $ | 41.42 | $ | 117.86 | $ | 0.83 | $ | 13.19 | |||||||||||||||
| Successor | |||||||||||||||||||
| Year Ended December 31, 2019 | |||||||||||||||||||
| Seaborne Thermal Mining | Seaborne Metallurgical Mining | Powder River Basin Mining | Midwestern U.S. Mining | Western U.S. Mining | |||||||||||||||
| (Amounts in millions, except per ton data) | |||||||||||||||||||
| Tons sold | 19.5 | 8.1 | 108.1 | 16.0 | 11.9 | ||||||||||||||
| Revenues | $ | 971.7 | $ | 1,033.1 | $ | 1,228.7 | $ | 669.7 | $ | 639.7 | |||||||||
| Reporting Segment Costs | 642.3 | 892.9 | 1,007.5 | 539.0 | 409.0 | ||||||||||||||
| Adjusted EBITDA | 329.4 | 140.2 | 221.2 | 130.7 | 230.7 | ||||||||||||||
| Revenues per Ton | $ | 49.69 | $ | 127.62 | $ | 11.37 | $ | 41.90 | $ | 53.48 | |||||||||
| Costs per Ton | 32.84 | 110.30 | 9.32 | 33.72 | 34.19 | ||||||||||||||
| Adjusted EBITDA Margin per Ton | 16.85 | 17.32 | 2.05 | 8.18 | 19.29 | ||||||||||||||
| Successor | |||||||||||||||||||
| Year Ended December 31, 2018 | |||||||||||||||||||
| Seaborne Thermal Mining | Seaborne Metallurgical Mining | Powder River Basin Mining | Midwestern U.S. Mining | Western U.S. Mining | |||||||||||||||
| (Amounts in millions, except per ton data) | |||||||||||||||||||
| Tons sold | 19.1 | 11.0 | 120.3 | 18.9 | 14.7 | ||||||||||||||
| Revenues | $ | 1,099.2 | $ | 1,553.0 | $ | 1,424.8 | $ | 801.0 | $ | 592.0 | |||||||||
| Reporting Segment Costs | 647.2 | 1,111.6 | 1,140.3 | 655.8 | 446.6 | ||||||||||||||
| Adjusted EBITDA | 452.0 | 441.4 | 284.5 | 145.2 | 145.4 | ||||||||||||||
| Revenues per Ton | $ | 57.58 | $ | 141.06 | $ | 11.84 | $ | 42.44 | $ | 40.20 | |||||||||
| Costs per Ton | 33.90 | 100.97 | 9.47 | 34.75 | 30.33 | ||||||||||||||
| Adjusted EBITDA Margin per Ton | 23.68 | 40.09 | 2.37 | 7.69 | 9.87 | ||||||||||||||
| Year Ended December 31, 2021 | |||||||||||||||||||||||
| Seaborne Thermal Mining | Seaborne Metallurgical Mining | Powder River Basin Mining | Other U.S. Thermal Mining | ||||||||||||||||||||
| (Amounts in millions, except per ton data) | |||||||||||||||||||||||
| Tons sold | 17.3 | 5.5 | 88.4 | 16.9 | |||||||||||||||||||
| Revenue | $ | 934.0 | $ | 727.7 | $ | 971.2 | $ | 689.1 | |||||||||||||||
| Total Reporting Segment Costs | 580.9 | 549.5 | 836.3 | 524.9 | |||||||||||||||||||
| Adjusted EBITDA | $ | 353.1 | $ | 178.2 | $ | 134.9 | $ | 164.2 | |||||||||||||||
| Revenue per Ton | $ | 54.09 | $ | 131.83 | $ | 10.99 | $ | 40.75 | |||||||||||||||
| Costs per Ton | 33.64 | 99.55 | 9.46 | 31.04 | |||||||||||||||||||
| Adjusted EBITDA Margin per Ton | $ | 20.45 | $ | 32.28 | $ | 1.53 | $ | 9.71 | |||||||||||||||
Free Cash Flow is defined as net cash provided by operating activities less net cash used in investing activities and excludes cash outflows related to business combinations. See the table below for a reconciliation of Free Cash Flow to its most comparable measure under U.S. GAAP.
| Year Ended December 31, | |||||||||||||||||
| 2022 | 2021 | ||||||||||||||||
| (Dollars in millions) | |||||||||||||||||
| Net cash provided by operating activities | $ | 1,173.6 | $ | 420.0 | |||||||||||||
| Net cash used in investing activities | (28.7) | (131.5) | |||||||||||||||
| Free Cash Flow | $ | 1,144.9 | $ | 288.5 | |||||||||||||
| Successor | |||||||
| Year Ended December 31, | |||||||
| 2019 | 2018 | ||||||
| (Dollars in millions) | |||||||
| Net cash provided by operating activities | $ | 677.4 | $ | 1,489.7 | |||
| Net cash used in investing activities | (261.3 | ) | (517.3 | ) | |||
| Add back: Amount attributable to acquisition of Shoal Creek Mine | 2.4 | 387.4 | |||||
| Free Cash Flow | $ | 418.5 | $ | 1,359.8 | |||
Liquidity and Capital Resources
Overview
| Peabody Energy Corporation | 2022 Form 10-K | 71 | ||||||
Any future determinations to return capital to stockholders, such as dividends or share repurchases will be at the discretion of our Board of Directors and will depend on a variety of factors, including the restrictions set forth under ourthe Company’s debt and surety agreements, ourits net income or other sources of cash, liquidity position and potential alternative uses of cash, such as internal development projects or acquisitions, as well as economic conditions and expected future financial results. OurThe Company’s ability to declare dividends or repurchase shares or early retire debt in the future will depend on ourits future financial performance, which in turn depends on the successful implementation of ourits strategy and on financial, competitive, regulatory, technical and other factors, general economic conditions, demand for and selling prices of coal and other factors specific to ourits industry, many of which are beyond ourthe Company’s control.
| December 31, | |||||||
| 2019 | 2018 | ||||||
| (Dollars in millions) | |||||||
| 6.000% Senior Secured Notes due March 2022 | $ | 459.0 | $ | 500.0 | |||
| 6.375% Senior Secured Notes due March 2025 | 500.0 | 500.0 | |||||
| Senior Secured Term Loan due 2025, net of original issue discount | 392.1 | 395.9 | |||||
| Finance lease and other obligations | 15.2 | 40.0 | |||||
| Less: Debt issuance costs | (55.5 | ) | (68.9 | ) | |||
| 1,310.8 | 1,367.0 | ||||||
| Less: Current portion of long-term debt | 18.3 | 36.5 | |||||
| Long-term debt | $ | 1,292.5 | $ | 1,330.5 | |||
Liquidity
As of December 31, 2019, our available liquidity was $1,275.8 million, which was comprised of cash and cash equivalents and availability under our revolving credit facility and receivables securitization program described below. As of December 31, 2019, our2022, the Company’s cash balances totaled $732.2$1,307.3 million, including approximately $644.9$412 million held by U.S. entities, $62.8subsidiaries, approximately $863 million held by Australian subsidiaries, and the remaining balanceremainder held by other foreign subsidiaries.subsidiaries in accounts predominantly domiciled in the U.S. A significant majority of the cash held by ourthe Company’s foreign subsidiaries is in accounts domiciled in the U.S. and denominated in U.S. dollars. This cash is generally used to support non-U.S. liquidity needs, including capital and operating expenditures in Australia. During 2019, we repatriatedFrom time to time, the Company may repatriate excess cash from its foreign subsidiaries to the U.S. During the year ended December 31, 2022, the Company repatriated approximately $420 million previously held by foreign subsidiaries.$1.3 billion. If we repatriate additional foreign-held cash is repatriated in the future, we dothe Company does not expect restrictions or potential taxes towill have a material effect to its near-term liquidity.
The Company’s available liquidity increased from $995.9 million as of December 31, 2021 to $1,317.8 million as of December 31, 2022. Available liquidity was comprised of the following:
| December 31, | |||||||||||||||||
| 2022 | 2021 | ||||||||||||||||
| (Dollars in millions) | |||||||||||||||||
| Cash and cash equivalents | $ | 1,307.3 | $ | 954.3 | |||||||||||||
| Credit facility availability | 3.5 | 15.3 | |||||||||||||||
| Accounts receivable securitization program availability | 7.0 | 26.3 | |||||||||||||||
| Total liquidity | $ | 1,317.8 | $ | 995.9 | |||||||||||||
Collateral Requirements
In November 2020, the Company entered into an agreement with the providers of its surety bond portfolio to resolve previous collateral demands. In accordance with the agreement, the Company initially provided $75.0 million of collateral, in the form of letters of credit. The Company subsequently granted second liens on our overall$200.0 million of certain mining equipment and is further required to post an additional $25.0 million of collateral per year from 2021 through 2024 for the benefit of the surety providers. The collateral postings further increase to the extent the Company generates more than $100.0 million of free cash flow (as defined in the surety agreement) in any twelve-month period or has cumulative asset sales in excess of $10.0 million, as of the last quarter end during the term of the agreement. Based upon the Company’s free cash flow since entering into the surety agreement, additional collateral of $102.4 million was posted during the year ended December 31, 2022 and $74.4 million was posted in January 2023, in the form of cash-collateralized letters of credit. The Company is unable to accurately estimate future additional collateral postings due to the sensitivity of free cash flow to external market factors such as coal pricing.
Under the agreement, the relevant surety providers agreed to a standstill through December 31, 2025, during which time, the surety providers will not demand collateral incremental to that described above, draw on letters of credit posted for the benefit of themselves or cancel any existing surety bond. The Company will not pay dividends or make share repurchases during the standstill period, unless otherwise agreed between parties.
The Company is currently in negotiations with its surety providers to amend the existing agreement, including a modification to permit shareholder returns.
| Peabody Energy Corporation | 2022 Form 10-K | 72 | ||||||
Collateralized Letter of Credit Agreement
In February 2022, the Company entered into a new agreement, which provides up to $250.0 million of capacity for irrevocable standby letters of credit, expected to primarily support reclamation bonding requirements. The agreement requires the Company to provide cash collateral at a level of 103% of the aggregate amount of letters of credit outstanding under the arrangement (limited to $5.0 million total excess collateralization.) Outstanding letters of credit bear a fixed fee in the amount of 0.75% per annum. The Company receives a variable deposit rate on the amount of cash collateral posted in support of letters of credit. The agreement has an initial expiration date of December 31, 2025. At December 31, 2022, letters of credit of $103.3 million were outstanding under the agreement, which were collateralized by cash of $111.0 million, which includes interest earned on deposits.
Margin Requirements
From time to time, the Company enters into hedging arrangements, including economic hedging arrangements, to manage various risks, including coal price volatility. Most hedging arrangements require the Company to post margin with its clearing broker based on the value of the related instruments and other credit factors. If the fair value of its exchange-cleared hedge portfolio moves significantly, the Company could be required to post additional margin, which could negatively impact its liquidity.
During 2022, the Company’s margin requirements have been driven primarily by coal derivative contracts entered into in the first half of 2021 related to 1.9 million metric tons of production at the Wambo Underground Mine in the Company’s Seaborne Thermal Mining segment. Based on planned production, the contracts were expected to settle at a rate of 1.2 million metric tons in 2022 and 0.7 million metric tons in 2023.
High demand and tight supply for coal globally during 2022 has resulted in a substantial rise in seaborne thermal coal prices, which has been amplified by the Russian-Ukrainian conflict resulting in unprecedented upward volatility in Newcastle coal pricing since late February 2022. The Newcastle financial price reached over $450 per metric ton during 2022, compared to approximately $166 per metric ton on December 31, 2021. As a result, the Company’s total initial and variation margin requirements reached approximately $750 million during March 2022. Margin is returned to the Company upon reductions in the underlying market coal price or, absent such reductions, cash is recovered as the Company delivers coal into the market at spot prices.
In order to meet its near-term liquidity requirements, particularly with respect to cash margin, the Company entered into a $150 million unsecured revolving credit facility in March 2022. Concurrently with this agreement, the Company entered into an agreement for at-the-market equity offerings of up to $225.0 million of the Company’s common stock. During the three months ended March 31, 2022, the Company borrowed and repaid $225.0 million under the revolving credit facility using net proceeds of $222.0 million from at-the-market issuances of 10.1 million shares of common stock and available cash. The Company made no additional borrowings and terminated the facility prior to its scheduled 2025 maturity, on August 4, 2022.
To reduce exposure to additional margin requirements, during 2022, the Company converted 0.8 million metric tons of financial hedges into fixed price physical sales. As of December 31, 2022, 0.6 million metric tons remain outstanding and are projected to settle during the first half of 2023.
On December 31, 2022, the Company had $255.5 million of margin posted. On February 17, 2023, the Company had $80.5 million of margin posted. For additional information regarding the Company’s coal derivative contracts, refer to Part II, Item 7A. “Quantitative and Qualitative Disclosures About Market Risk.”
| Peabody Energy Corporation | 2022 Form 10-K | 73 | ||||||
Indebtedness
The Company’s total indebtedness as of December 31, 2022 and 2021 is presented in the table below.
| December 31, | |||||||||||
| Debt Instrument (defined below, as applicable) | 2022 | 2021 | |||||||||
| (Dollars in millions) | |||||||||||
| 6.000% Senior Secured Notes due March 2022 (2022 Notes) | $ | — | $ | 23.1 | |||||||
| 8.500% Senior Secured Notes due December 2024 (2024 Peabody Notes) | — | 62.6 | |||||||||
| 10.000% Senior Secured Notes due December 2024 (2024 Co-Issuer Notes) | — | 193.9 | |||||||||
| Senior Secured Term Loan due 2024 (Co-Issuer Term Loans) | — | 206.0 | |||||||||
| 6.375% Senior Secured Notes due March 2025 (2025 Notes) | — | 334.9 | |||||||||
| Senior Secured Term Loan due 2025, net of original issue discount (Senior Secured Term Loan) | — | 322.8 | |||||||||
| 3.250% Convertible Senior Notes due March 2028 (2028 Convertible Notes) | 320.0 | — | |||||||||
| Finance lease obligations | 23.6 | 29.3 | |||||||||
| Less: Debt issuance costs | (9.8) | (34.8) | |||||||||
| 333.8 | 1,137.8 | ||||||||||
| Less: Current portion of long-term debt | 13.2 | 59.6 | |||||||||
| Long-term debt | $ | 320.6 | $ | 1,078.2 | |||||||
As further described below, during 2021, the Company completed a significant debt restructuring to extend maturities on its existing debt and obtain covenant relief. Subsequent to these restructuring activities, the Company utilized various methods allowable or required under its relevant debt agreements to retire all of its senior secured long-term debt by December 31, 2022, as only the 2028 Convertible Notes, which are further described below, and finance lease obligations remain outstanding.
The Company’s remaining indebtedness requires estimated contractual principal and interest payments, assuming interest rates in effect at December 31, 2022, of approximately $25 million in 2023, $16 million in 2024, $14 million in 2025, $13 million in 2026, $11 million in 2027 and $322 million thereafter.
Cash interest payments amounted to $118.5 million, $174.9 million and $126.9 million during the years ended December 31, 2022, 2021, and 2020, respectively.
2021 Debt Restructuring
During the first quarter of 2021, the Company completed a series of financing transactions to provide the Company with maturity extensions and covenant relief, while allowing it to maintain near-term operating liquidity. These transactions included a senior notes exchange, a revolving credit facility exchange, various amendments to the Company’s existing debt agreements and a support agreement with the Company’s surety bond providers. These transactions were preceded by an organizational realignment in which the Company formed certain wholly-owned subsidiaries (the Co-Issuers) to indirectly own and conduct the operations of the Company’s Wilpinjong Mine in Australia and the designation of such entities as unrestricted subsidiaries under the Company’s then-existing credit agreement (Credit Agreement) and senior notes’ indenture.
The senior notes exchange involved the tender of $398.7 million aggregate principal amount of the Company’s 2022 Notes for aggregate consideration consisting of (a) $193.9 million aggregate principal amount of new 2024 Co-Issuer Notes, (b) $195.1 million aggregate principal amount of new 2024 Peabody Notes issued by the Company and (c) a cash payment of approximately $9.4 million.
Concurrently with the senior notes exchange, the Company solicited consents from holders of the 2022 Notes to certain proposed amendments to its existing senior notes’ indenture to (i) eliminate substantially all of the restrictive covenants, certain events of default applicable to the 2022 Notes and certain other provisions contained in their indenture and (ii) release the collateral securing the 2022 Notes and eliminate certain other related provisions. The Company received the requisite consents from holders of the 2022 Notes and entered into a supplemental indenture to reflect such amendments.
| Peabody Energy Corporation | 2022 Form 10-K | 74 | ||||||
The Company also restructured $216.0 million of existing revolving loans under the Credit Agreement by (i) paying down $10.0 million aggregate principal amount of such loans, (ii) compelling the Co-Issuers to incur $206.0 million of Co-Issuer Term Loans under a separate credit agreement, (iii) entering into a letter of credit facility (the Company LC Agreement) and (iv) amending the Credit Agreement.
Under the Company LC Agreement, the Company obtained a $324.0 million letter of credit facility under which its existing letters of credit under the Credit Agreement were deemed to be issued. Undrawn letters of credit under the Company LC Agreement bear interest at 6.00% per annum and unused commitments are subject to a 0.50% per annum commitment fee. The Company LC Agreement was subsequently amended during 2022 to mandatorily reduce its capacity by approximately $22 million to make allowable certain previously restricted payments for joint venture investments. The amendment creates an investment basket which allows payments of $30.0 million per year specifically limited to investment in renewable energy-related projects. The Company has no contractual commitment for such project investment. Unused portions of the basket carryover from year-to-year, and the total amount of investment will further reduce the credit facility capacity by a like amount, or a minimum of $10.0 million per year, through the maturity of the credit facility. In February 2023, the Company LC Agreement was further amended to reduce its capacity by an additional $65.0 million, accelerate its expiration date to December 31, 2023 from December 31, 2024, and eliminate the prepayment premium due upon any reduction of commitments thereunder prior to July 29, 2023.
The Company expects to utilize its collateralized letter of credit agreement to offset reductions in the capacity of the Company LC Agreement.
Completion of the 2021 debt restructuring transactions allowed the Company to finalize the surety transaction support agreement described above.
2021 Debt Retirements
During the remainder of 2021, the Company retired $293.3 million of debt principal for cash at an aggregate cost of $250.3 million, and $106.1 million of debt principal in exchange for 10.0 million shares of its common stock, as further described below.
In March 2021, as a requirement of the senior notes exchange, the Company purchased $22.4 million of the 2024 Peabody Notes at 80% of their accreted value, plus accrued and unpaid interest.
In June 2021, the Company announced an at-the-market equity offering program pursuant to which, as amended, the Company could offer and sell up to 32.5 million shares of its common stock. During the year ended December 31, 2021, the Company sold approximately 24.8 million shares for net cash proceeds of $269.8 million. Such proceeds were utilized, in part, for the retirement of debt as described below.
During the year ended December 31, 2019, we2021, the Company retired $91.4 million of 2024 Peabody Notes, $117.8 million of 2025 Notes and $61.7 million of its Senior Secured Term Loan primarily through various open market purchases at an aggregate cost of $232.4 million.
Also during the year ended December 31, 2021, the Company completed multiple bilateral transactions with note holders 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.
2022 Debt Retirements
During 2022, the Company retired $1,143.8 million of debt principal for cash at an aggregate cost of $1,172.0 million, as further described below. Such amounts exclude the $225.0 million principal amount borrowed and repaid under the now-terminated revolving facility described above.
On March 31, 2022, the Company retired the remaining principal balance of 2022 Notes upon maturity for $23.1 million.
| Peabody Energy Corporation | 2022 Form 10-K | 75 | ||||||
During the three months ended March 31, 2022, $62.5 million principal amount of the 2024 Peabody Notes was retired using proceeds from the offering of 2028 Convertible Notes, as further described below, and the remaining $0.1 million principal amount was retired through a mandatory repurchase offer required under the terms of their indenture and the Company LC Agreement. Such mandatory repurchase offers were required when the Company made open market repurchases of its debt. In general, the repurchase offers equated to 25% of the principal amount of priority lien debt repurchased in the preceding quarter at a price equal to the weighted average repurchase price paid dividendsover that quarter. In addition to the $0.1 million principal amount of $258.12024 Peabody Notes repurchased through such offers, the Company repurchased $42.2 million of aggregate priority lien obligations under the Company LC Agreement during 2022 at approximately 95%. The repurchases of Company LC Agreement commitments were effected by the posting of $40.1 million of collateral with the administrative agent and did not reduce the availability under the facility.
In March 2022, $257.4 million principal amount of the 2025 Notes was retired using proceeds from the offering of 2028 Convertible Notes, as further described below. The remaining 2025 Notes were retired through an open market repurchase of $11.4 million principal amount at 98.00% in September 2022 and, in accordance with the notes’ indenture, a voluntary prepayment of $66.1 million principal amount at 101.59% in December 2022.
The Senior Secured Term Loan was retired through various open market purchases of $44.1 million principal amount throughout 2022 at an aggregate cost of $42.1 million, scheduled quarterly principal amortization payments of $3.0 million, and, in accordance with the terms of the Credit Agreement, a voluntary prepayment of $276.2 million principal amount at par in December 2022.
The 2024 Co-Issuer Notes and the Co-Issuer Term Loans were subject to mandatory prepayment offers at the end of each six-month period, beginning with June 30, 2021, whereby the Excess Cash Flow (as defined in the 2024 Co-Issuer Notes indenture) generated by the Wilpinjong Mine during each such period could be applied to the principal of such notes and loans on a pro rata basis, provided that the liquidity attributable to the Wilpinjong Mine would not fall below $60.0 million. Such prepayments could be accepted or declined at the option of the debt holders. Based upon the Wilpinjong Mine’s results for the six-month periods ended December 31, 2021 and June 30, 2022 and the resultant mandatory prepayment offers, during 2022, the Company prepaid $18.5 million principal amount of 2024 Co-Issuer Notes at an aggregate cost of $19.2 million and $17.2 million principal amount of Co-Issuer Term Loans at par.
Voluntary repurchases of Co-Issuer Term Loans were permissible through various methods, including a modified Dutch auction process in which the Company could solicit acceptable prices from holders. During the year ended December 31, 2022, the Company solicited bids from all holders of Co-Issuer Term Loans at various dates for the repurchase of the remaining outstanding principal amount, resulting in the valid tender and purchase of $185.9 million principal amount at an aggregate cost of $195.8 million.
The underlying terms of the 2024 Co-Issuer Notes and Co-Issuer Term Loans required parity between the holders of Co-Issuer Term Loans and holders of the 2024 Co-Issuer Notes with respect to repurchase offers such as those undertaken through the auction processes described above. As such, the Company solicited commensurate bids from all holders of 2024 Co-Issuer Notes at various dates during the year ended December 31, 2022 for the repurchase of the remaining outstanding principal amount, resulting in the valid tender and purchase of $147.3 million principal amount at an aggregate cost of $154.1 million.
Subsequent to the modified Dutch auction processes and related transactions, during the fourth quarter of 2022, the Company voluntarily prepaid the remaining $28.1 million principal amount of 2024 Co-Issuer Notes and $2.9 million principal amount of Co-Issuer Term Loans at an aggregate cost of $32.8 million, including $200certain make whole premium amounts.
3.250% Convertible Senior Notes due 2028
On March 1, 2022, through a private offering, the Company issued $320.0 million for a supplemental dividend, made stock repurchases totaling $329.9 million,in aggregate principal amount of 3.250% Convertible Senior Notes due 2028 (the 2028 Convertible Notes). The 2028 Convertible Notes are senior unsecured obligations of the Company and made open-market purchasesare governed under an indenture.
The Company used the proceeds of $41.0the offering of the 2028 Convertible Notes to redeem the remaining $62.5 million of our senior secured notes for $39.9its outstanding 2024 Peabody Notes and, together with available cash, approximately $257.4 million plus accrued interest. No additional dividendsof its outstanding 2025 Notes, and to pay related premiums, fees and expenses relating to the offering of the 2028 Convertible Notes and the redemptions.
The 2028 Convertible Notes will mature on March 1, 2028, unless earlier converted, redeemed or stock repurchases are currently planned.
| Peabody Energy Corporation | 2022 Form 10-K | 76 | ||||||
During the fourth quarter of 2022, the Company’s reported common stock prices reached levels which prompted the conversion feature of the 2028 Convertible Notes. As a result, the 2028 Convertible Notes are convertible at the option of the holders during 2017, we entered into a credit agreementthe first quarter of 2023. The Company cannot currently satisfy the conversion obligation in cash because the terms of the Credit Agreement generally prohibit the Company from retiring unsecured debt with cash. It is the Company’s current intent and relatedpolicy to settle any conversions of notes through shares of its common stock. Through February 17, 2023, the Company has not received any conversion requests and does not anticipate receiving any conversion requests in the near term loanas the market value of the 2028 Convertible Notes exceeds their conversion value.
Covenant Compliance
The Company was compliant with all relevant covenants under its debt agreements at December 31, 2022, including the minimum aggregate liquidity requirement under the Company LC Agreement which we originally borrowed $950.0requires the Company’s restricted subsidiaries to maintain minimum aggregate liquidity of $125.0 million and have repaid $557.0 millionat the end of each quarter through December 31, 2019.2023. The term loan requires quarterly principal payments of $1.0 million and periodic interest payments, currently at LIBOR plus 2.75%, through December 2024 with the remaining balance due in March 2025.
Accounts Receivable Securitization Program
As described in Note 25.20. “Financial Instruments, Guarantees With Off-Balance-Sheet Risk and Other Guarantees” of the accompanying unaudited condensed consolidated financial statements, wethe Company entered into an amended accounts receivable securitization program during 2017 which currently expires2017. The securitization program was amended in 2022. The program provides for upJanuary 2022 to extend its maturity to January 2025 and reduce the available funding capacity from $250.0 million in funding,to $175.0 million. Funding capacity is limited to the availability of eligible receivables and is accounted for as a secured borrowing. Funding capacity under the program may also be providedutilized for letters of credit in support of other obligations. At December 31, 2019, we2022, the Company had no outstanding borrowings and $132.7$168.0 million of letters of credit providedoutstanding under the program. The letters of credit areprogram, which were primarily in support of portions of our obligations forthe Company’s reclamation workers’ compensation and postretirement benefits. Availabilityobligations. The Company had no cash collateral posted under the program, which is adjusted for certain ineligible receivables, was $45.0 millionSecuritization Program at December 31, 20192022.
The securitization program was amended again in February 2023 to increase the available funding capacity to $225.0 million and there was noadjust the relevant interest rate for borrowings to a secured overnight financing rate (SOFR).
Capital Expenditures
For 2023, the Company is targeting total capital expenditures of approximately $325 million. Approximately $200 million of such amount is appropriated to major projects and growth capital expenditures, including approximately $120 million for the initial redevelopment of the Company’s North Goonyella mine.
Other Requirements
The Company will incur significant future cash collateral requirement.outflows for certain liabilities related to its prior mining activities and former employees. Such cash flows pertain to postretirement benefit plans, work-related injuries and illnesses, defined benefit pension plans, mine reclamation and end-of-mine closure costs and exploration obligations and are estimated to amount to approximately $235 million in 2023, $100 million in 2024, $110 million in 2025, $100 million in 2026, $100 million in 2027 and $1,685 million thereafter.
The Company’s operating lease commitments, excluding potential contingent rental amounts, will require cash payments of approximately $19 million in 2023, $7 million in 2024 and $4 million thereafter.
| Peabody Energy Corporation | ||||||||
The following table summarizes ourthe Company’s cash flows for the yearyears ended December 31, 20192022 and 2018,2021, as reported in the accompanying consolidated financial statements:statements. Free Cash Flow is a financial measure not recognized in accordance with U.S. GAAP. Refer to the “Reconciliation of Non-GAAP Financial Measures” section above for definitions and reconciliations to the most comparable measures under U.S. GAAP.
| Successor | ||||||||||||||||||||||||
| Year Ended December 31, | Year Ended December 31, | |||||||||||||||||||||||
| 2019 | 2018 | 2022 | 2021 | |||||||||||||||||||||
| (Dollars in millions) | (Dollars in millions) | |||||||||||||||||||||||
| Net cash provided by operating activities | $ | 677.4 | $ | 1,489.7 | Net cash provided by operating activities | $ | 1,173.6 | $ | 420.0 | |||||||||||||||
| Net cash used in investing activities | (261.3 | ) | (517.3 | ) | Net cash used in investing activities | (28.7) | (131.5) | |||||||||||||||||
| Net cash used in financing activities | (701.3 | ) | (1,025.2 | ) | Net cash used in financing activities | (681.6) | (43.4) | |||||||||||||||||
| Net change in cash, cash equivalents and restricted cash | (285.2 | ) | (52.8 | ) | Net change in cash, cash equivalents and restricted cash | 463.3 | 245.1 | |||||||||||||||||
| Cash, cash equivalents and restricted cash at beginning of period | 1,017.4 | 1,070.2 | Cash, cash equivalents and restricted cash at beginning of period | 954.3 | 709.2 | |||||||||||||||||||
| Cash, cash equivalents and restricted cash at end of period | $ | 732.2 | $ | 1,017.4 | Cash, cash equivalents and restricted cash at end of period | $ | 1,417.6 | $ | 954.3 | |||||||||||||||
| Net cash provided by operating activities | $ | 677.4 | $ | 1,489.7 | Net cash provided by operating activities | $ | 1,173.6 | $ | 420.0 | |||||||||||||||
| Net cash used in investing activities | (261.3 | ) | (517.3 | ) | Net cash used in investing activities | (28.7) | (131.5) | |||||||||||||||||
| Add back: Acquisition of Shoal Creek Mine | 2.4 | 387.4 | ||||||||||||||||||||||
| Free Cash Flow | $ | 418.5 | $ | 1,359.8 | Free Cash Flow | $ | 1,144.9 | $ | 288.5 | |||||||||||||||
Operating Activities. The decreasenet increase in net cash provided by operating activities for the year ended December 31, 20192022 compared to the prior year ended December 31, 2018 was driven by the following:
Investing Activities. The decrease in net cash used in investing activities for the year ended December 31, 20192022 compared to the prior year ended December 31, 2018 was driven by the following:
Financing Activities. The decreaseincrease in net cash used in financing activities for the year ended December 31, 20192022 compared to the prior year was driven by higher repayments of debt principal ($1,122.0 million), decreased proceeds from common stock issuances in the current year ($47.8 million) and higher distributions to non-controlling interests ($13.6 million) partially offset by proceeds from long-term debt issuances of $545.0 million during the year ended December 31, 2018 was driven by the following:2022.
| Payments Due By Year | |||||||||||||||||||
| Total | Less than 1 Year | 2 - 3 Years | 4 - 5 Years | More than 5 Years | |||||||||||||||
| (Dollars in millions) | |||||||||||||||||||
Long-term debt obligations (principal and interest) (1) | $ | 1,674.0 | $ | 81.5 | $ | 600.7 | $ | 106.6 | $ | 885.2 | |||||||||
| Finance lease obligations (principal and interest) | 15.4 | 14.5 | 0.8 | 0.1 | — | ||||||||||||||
Operating lease obligations (2) | 95.1 | 33.7 | 37.2 | 17.0 | 7.2 | ||||||||||||||
Unconditional purchase obligations (3) | 39.7 | 39.7 | — | — | — | ||||||||||||||
| Coal reserve lease and royalty obligations | 59.4 | 5.2 | 10.4 | 9.5 | 34.3 | ||||||||||||||
Take-or-pay obligations (4) | 1,067.3 | 116.1 | 185.0 | 153.9 | 612.3 | ||||||||||||||
Other long-term liabilities (5) | 2,958.9 | 269.7 | 412.7 | 278.3 | 1,998.2 | ||||||||||||||
| Total contractual cash obligations | $ | 5,909.8 | $ | 560.4 | $ | 1,246.8 | $ | 565.4 | $ | 3,537.2 | |||||||||
In the normal course of business, we arethe Company is a party to various guarantees and financial instruments that carry off-balance-sheet risk and are not reflected in the accompanying consolidated balance sheets. At December 31, 2019,2022, such instruments included $1,609.2$1,376.8 million of surety bonds and $200.5$569.6 million of letters of credit. Such financial instruments provide support for ourits reclamation bonding requirements, lease obligations, insurance policies and various other performance guarantees. WeThe Company periodically evaluateevaluates the instruments for on-balance-sheet treatment based on the amount of exposure under the instrument and the likelihood of required performance. We doThe Company does not expect any material losses to result from these guarantees or off-balance-sheet instruments in excess of liabilities provided for in ourits consolidated balance sheets.
| Peabody Energy Corporation | 2022 Form 10-K | 78 | ||||||
As of December 31, 2022, the Company was party to financial instruments with off-balance sheet risk in our liquiditysupport of the following obligations:
| Reclamation | Health and welfare (1) | Contract performance (2) | Leased property and equipment | Other (3) | Total | ||||||||||||||||||||||||||||||
| (Dollars in millions) | |||||||||||||||||||||||||||||||||||
| Surety bonds and bank guarantees | $ | 1,250.1 | $ | 40.5 | $ | 35.2 | $ | 35.0 | $ | 16.0 | $ | 1,376.8 | |||||||||||||||||||||||
| Letters of credit outstanding under letter of credit facilities | 300.8 | 91.9 | 3.9 | 5.0 | — | 401.6 | |||||||||||||||||||||||||||||
| Letters of credit outstanding under accounts receivable securitization program | 137.0 | 19.2 | 11.8 | — | — | 168.0 | |||||||||||||||||||||||||||||
| 1,687.9 | 151.6 | 50.9 | 40.0 | 16.0 | 1,946.4 | ||||||||||||||||||||||||||||||
Less: Letters of credit in support of surety bonds (4) | (431.7) | (31.9) | (4.1) | (1.2) | — | (468.9) | |||||||||||||||||||||||||||||
| Obligations supported, net | $ | 1,256.2 | $ | 119.7 | $ | 46.8 | $ | 38.8 | $ | 16.0 | $ | 1,477.5 | |||||||||||||||||||||||
(1)Obligations include pension and health care plans, workers’ compensation, and property and casualty insurance.
(2) Obligations pertain to customer and vendor contracts.
(3) Obligations primarily pertain to the disturbance or alteration of public roadways in connection with the Company’s mining activities that is subject to future restoration.
(4) Serve as collateral for certain surety bonds at the request of surety bond providers.
Not presented in the above table is approximately $187 million of cash collateral posted by the Company and included in the accompanying consolidated balance sheet at December 31, 2022. Such collateral is primarily in support of the financial instruments noted above, including in relation to the Company’s collateralized letter of credit agreement, mandatory repurchases of credit facility capacity, additional collateral in support of certain surety bonds, and amounts held directly with beneficiaries which are not supported by surety bonds.
Financial assurances associated with new reclamation bonding requirements, surety bonds or other obligations are required to be collateralized bymay require additional collateral in the form of cash or letters of credit.credit causing a decline in the Company’s liquidity.
As described in Note 25.20. “Financial Instruments, Guarantees With Off-Balance-Sheet Risk and Other Guarantees” to the accompanying consolidated financial statements, we arethe Company is required to provide various forms of financial assurance in support of ourits mining reclamation obligations in the jurisdictions in which we operate.it operates. Such requirements are typically established by statute or under mining permits. Historically, such assurances have taken the form of third-party instruments such as surety bonds, bank guarantees and letters of credit, as well as self-bonding arrangements in the U.S. Following our emergence from the Chapter 11 Cases, we shifted away from extensive self-bonding in the U.S. in favor of increased usage of surety bonds and similar third-party instruments. This change in practice has had an unfavorable impact on our liquidity due to increased collateral requirements and surety and related fees.
At December 31, 2019, we2022, the Company had total asset retirement obligations of $752.3$750.0 million which were backed by a combination of surety bonds, bank guarantees and letters of credit.
Bonding requirement amounts may differ significantly from the related asset retirement obligation because such requirements are calculated under the assumption that reclamation begins currently, whereas ourthe Company’s accounting liabilities are discounted from the end of a mine’s economic life (when final reclamation work would begin) to the balance sheet date.
Guarantees and Other Financial Instruments with Off-Balance Sheet Risk. See Note 25.20. “Financial Instruments, Guarantees With Off-Balance-Sheet Risk and Other Guarantees” to ourthe accompanying consolidated financial statements for a discussion of ourthe Company’s accounts receivable securitization program and guarantees and other financial instruments with off-balance sheet risk.
Critical Accounting Policies and Estimates
| Peabody Energy Corporation | 2022 Form 10-K | 79 | ||||||
Asset Retirement Obligations. We accountThe Company’s asset retirement obligations primarily consist of spending estimates for business combinationssurface land reclamation and support facilities at both surface and underground mines in accordance with applicable reclamation laws and regulations in the U.S. and Australia as defined by each mining permit. Asset retirement obligations are determined for each mine using the purchase method of accounting. The purchase method requires us to determine the fair value of all acquired assets, including identifiable intangible assets, and all assumed liabilities. The total cost of acquisitions is allocated to the underlying identifiable net assets, based on their respective estimated fair values. Determining the fair value of assets acquired and liabilities assumed requires management's judgment and the utilization of independent valuation experts, and often involves the use of significantvarious estimates and assumptions including, assumptions with respectamong other items, estimates of disturbed acreage as determined from engineering data, estimates of future costs to futurereclaim the disturbed acreage and the timing of these cash inflowsflows, escalated for inflation and outflows, discount ratesthen discounted using a credit-adjusted, risk-free rate. As changes in estimates occur (such as mine plan revisions, changes in estimated costs or changes in timing of the performance of reclamation activities), the revisions to the obligation and asset lives, among other items. Dueare recognized at the appropriate credit-adjusted, risk-free rate. If the Company’s assumptions do not materialize as expected, actual cash expenditures and costs that it incurs could be materially different than currently estimated. Moreover, regulatory changes could increase its obligation to perform reclamation and mine closing activities. Amortization associated with the unobservable inputs toCompany’s asset retirement obligation assets of $26.5 million for the valuation, the fair value would be considered Level 3year ended December 31, 2022 was included in “Depreciation, depletion and amortization” in the fair value hierarchy.
Impairment of Long-Lived Assets. We evaluate ourThe Company evaluates its long-lived assets held and used in operations for impairment as events and changes in circumstances indicate that the carrying amount of such assets might not be recoverable. Factors that would indicate potential impairment to be present include, but are not limited to, a sustained history of operating or cash flow losses, an unfavorable change in earnings and cash flow outlook, prolonged adverse industry or economic trends and a significant adverse change in the extent or manner in which a long-lived asset is being used or in its physical condition. WeThe Company generally dodoes not view short-term declines in thermal and metallurgical coal prices as a triggering event for conducting impairment tests because of historic price volatility. However, wethe Company generally viewviews a sustained trend of depressed coal pricing (for example, over periods exceeding one year) as an indicator of potential impairment. Because of the volatile and cyclical nature of coal prices and demand, it is reasonably possible that coal prices may decrease and/or fail to improve in the near term, which, absent sufficient mitigation such as an offsetting reduction in ourthe Company’s operating costs, may result in the need for future adjustments to the carrying value of ourits long-lived mining assets and mining-related investments.
Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. For ourits active mining operations, wethe Company generally groupgroups such assets at the mine level, or the mining complex level for mines that share infrastructure, with the exception of impairment evaluations triggered by mine closures. In those cases involving mine closures, the related assets are evaluated at the individual asset level for remaining economic life based on transferability to ongoing operating sites or for expected salvage. For ourits development and exploration properties and portfolio of surface land and coal reserve and resource holdings, we considerthe Company considers several factors to determine whether to evaluate those assets individually or on a grouped basis for purposes of impairment testing. Such factors include geographic proximity to one another, the expectation of shared infrastructure upon development based on future mining plans and whether it would be most advantageous to bundle such assets in the event of a sale to a third party.
When indicators of impairment are present, we evaluate ourthe Company evaluates its long-lived assets for recoverability by comparing the estimated undiscounted cash flows in the LOM plan expected to be generated by those assets under various assumptions to their carrying amounts. If such undiscounted cash flows indicate that the carrying value of the asset group is not recoverable, impairment losses are measured by comparing the estimated fair value of the asset group to its carrying amount. As quoted market prices are unavailable for ourthe Company’s individual mining operations, fair value is determined through the use of an expected present value technique based on the income approach, except for non-strategic coal reserves and resources, surface lands and undeveloped coal properties excluded from ourits long-range mine planning. In those cases, a market approach is utilized based on the most comparable market multiples available. The estimated future cash flows and underlying assumptions used to assess recoverability and, if necessary, measure the fair value of ourthe Company’s long-lived mining assets are derived from those developed in connection with ourits planning and budgeting process. We believe ourThe Company believes its assumptions to be consistent with those a market participant would use for valuation purposes. The most critical assumptions underlying ourits projections and fair value estimates include those surrounding future tons sold, coal prices for unpriced coal, production costs (including costs for labor, commodity supplies and contractors), transportation costs, foreign currency exchange rates and a risk-adjusted, cost of capital (all of which generally constitute unobservable Level 3 inputs under the fair value hierarchy), in addition to market multiples for non-strategic coal reserves and resources, surface lands and undeveloped coal properties excluded from ourthe Company’s long-range mine planning (which generally constitute Level 2 inputs under the fair value hierarchy).
| Peabody Energy Corporation | 2022 Form 10-K | 80 | ||||||
Impairment charges of $261.2 million ofrelated to long-lived assets of $9.5 million were recorded for the year ended December 31, 2019.2022. The assumptions used are based on ourthe Company’s best knowledge at the time we prepare ourit prepares its analysis but can vary significantly due to the volatile and cyclical nature of coal prices and demand, regulatory issues, unforeseen mining conditions, commodity prices and cost of labor. These types of changesfactors may cause usthe Company to be unable to recover all or a portion of the carrying value of ourits long-lived assets. We conducted a review of all other long-lived assets for recoverability as of December 31, 2019 and determined that no further impairment charge was necessary as of that date.
See Note 5.3. “Asset Impairment” to ourthe accompanying consolidated financial statements for additional information regarding impairment charges.
Income Taxes. We accountPeabody accounts for income taxes in accordance with accounting guidance which requires deferred tax assets and liabilities to be recognized using enacted tax rates for the effect of temporary differences between the book and tax bases of recorded assets and liabilities. The guidance also requires that deferred tax assets be reduced by a valuation allowance if it is “more likely than not” that some portion or all of the deferred tax asset will not be realized. In ourits evaluation of the need for a valuation allowance, we takePeabody takes into account various factors, including the expected level of future taxable income, available tax planning strategies, reversals of existing taxable temporary differences and taxable income in carryback years. As ofDuring the year ended December 31, 2019, we had2022, the Company released valuation allowances of $74.7 million recorded against the Australian NOLs and net deferred tax asset position due to the significant current year utilization of NOLs and expected future realization of the deferred tax assets. At December 31, 2022, the Company maintained valuation allowances for income taxes totaling $2,068.4$1,451.0 million. If actual results differ from the assumptions made in ourthe annual evaluation of ourits valuation allowance, wePeabody may record a change in valuation allowance through income tax expense in the period such determination is made.
See Note 12.8. “Income Taxes” to the accompanying consolidated financial statements for additional information regarding valuation allowances and unrecognized tax benefits and the Act.benefits.
Postretirement Benefit and Pension Liabilities. We havePeabody has long-term liabilities for ourits employees’ postretirement benefit costs and defined benefit pension plans. OurIts pension obligations are funded in accordance with the provisions of applicable laws and ourthe Company’s policies. Liabilities for postretirement benefit costs are funded at ourits discretion. In connection with fresh start reporting, we made an accounting policy election to prospectively record amounts attributable to actuarial valuation changes currently in earnings rather than recording such amounts within accumulated other comprehensive income and amortizing to expense over applicable time periods. Expense forFor the year ended December 31, 2019 for2022, Peabody recorded a total benefit related to postretirement benefit costs and pension liabilities totaled $24.8of $49.1 million, while employer contributions were $82.4$15.9 million. An actuarial lossgain of $61.7$30.6 million was recorded for the year ended December 31, 2019.2022.
Each of these liabilities is actuarially determined and we usePeabody uses various actuarial assumptions, including the discount rate, future cost trends, mortality tables, demographic assumptions and expected asset returns to estimate the costs and obligations for these items. OurPeabody’s discount rate is determined by utilizing a hypothetical bond portfolio model which approximates the future cash flows necessary to service ourits liabilities. We makeThe Company makes assumptions related to future trends for medical care costs in the estimates of postretirement benefit costs. OurIts medical trend assumption is developed by annually examining the historical trend of cost per claim data. 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. In addition, we makethe Company makes assumptions related to rates of return on plan assets. If ourits assumptions do not materialize as expected, actual cash expenditures and costs that we incurPeabody incurs could differ materially from ourits current estimates. Moreover, regulatory changes could affect ourPeabody’s obligation to satisfy these or additional obligations.
| Peabody Energy Corporation | 2022 Form 10-K | 81 | ||||||
For ourthe Company’s postretirement benefit obligation, assumed discount rates and health care cost trend rates have a significant effect on the expense and liability amounts reported for ourits health care plans. Below we havethe Company has provided two separate sensitivity analyses to demonstrate the significance of these assumptions in relation to reported amounts.
| For Year Ended December 31, 2022 | |||||||||||
| One-Percentage- Point Increase | One-Percentage- Point Decrease | ||||||||||
| (Dollars in millions) | |||||||||||
| Health care cost trend rate: | |||||||||||
| Effect on total net periodic postretirement benefit cost | $ | 0.5 | $ | (0.4) | |||||||
| Effect on total postretirement benefit obligation | $ | 11.3 | $ | (10.2) | |||||||
| For Year Ended December 31, 2019 | |||||||
One-Percentage- Point Increase | One-Percentage- Point Decrease | ||||||
| (Dollars in millions) | |||||||
| Health care cost trend rate: | |||||||
| Effect on total net periodic postretirement benefit cost | $ | 2.5 | $ | (2.3 | ) | ||
| Effect on total postretirement benefit obligation | $ | 57.3 | $ | (50.9 | ) | ||
| For Year Ended December 31, 2019 | For Year Ended December 31, 2022 | |||||||||||||||||
One-Half Percentage- Point Increase | One-Half Percentage- Point Decrease | One-Half Percentage- Point Increase | One-Half Percentage- Point Decrease | |||||||||||||||
| (Dollars in millions) | (Dollars in millions) | |||||||||||||||||
| Discount rate: | Discount rate: | |||||||||||||||||
| Effect on total net periodic postretirement benefit cost | $ | 1.3 | $ | (1.4 | ) | Effect on total net periodic postretirement benefit cost | $ | 0.9 | $ | (0.9) | ||||||||
| Effect on total postretirement benefit obligation | $ | (32.1 | ) | $ | 36.7 | Effect on total postretirement benefit obligation | $ | (6.0) | $ | 6.4 | ||||||||
| Expected return on assets: | Expected return on assets: | |||||||||||||||||
| Effect on total net periodic postretirement benefit cost | Effect on total net periodic postretirement benefit cost | $ | (0.1) | $ | 0.1 | |||||||||||||
For ourthe Company’s pension obligation, assumed discount rates and expected returns on assets have a significant effect on the expense and funded status amounts reported for ourits defined benefit pension plans. Below we havethe Company has provided two separate sensitivity analyses to demonstrate the significance of these assumptions in relation to reported amounts.
| For Year Ended December 31, 2019 | For Year Ended December 31, 2022 | |||||||||||||||||
One-Half Percentage- Point Increase | One-Half Percentage- Point Decrease | One-Half Percentage- Point Increase | One-Half Percentage- Point Decrease | |||||||||||||||
| (Dollars in millions) | (Dollars in millions) | |||||||||||||||||
| Discount rate: | Discount rate: | |||||||||||||||||
| Effect on total net periodic pension cost | $ | 1.9 | $ | (2.1 | ) | Effect on total net periodic pension cost | $ | 2.4 | $ | (2.7) | ||||||||
| Effect on defined benefit pension plans’ projected benefit obligation | $ | (41.3 | ) | $ | 45.1 | Effect on defined benefit pension plans’ projected benefit obligation | $ | (5.0) | $ | 5.4 | ||||||||
| Expected return on assets: | Expected return on assets: | |||||||||||||||||
| Effect on total net periodic pension cost | $ | (3.7 | ) | $ | 3.7 | Effect on total net periodic pension cost | $ | (3.7) | $ | 3.7 | ||||||||
As a result of discretionary contributions made in recent years, ourits defined benefit pension plans have become nearly fully funded. As a result of the funding level, the asset allocation mix reflected Peabody’s target asset mix of 100% fixed income investments and the pensions plans’ assets provide a significant hedge to the funded status against interest rate movements. If the discount rate moves, Peabody’s actual results would be different than those shown above as substantially all of the change in the discount rate should be offset by changes to the expected return on plan assets.
See Note 17.13. “Postretirement Health Care and Life Insurance Benefits” and Note 18.14. “Pension and Savings Plans” to the accompanying consolidated financial statements for additional information regarding postretirement benefit and pension plans.
Contingent liabilities. From time to time, we arePeabody is subject to legal and environmental matters related to ourits continuing and discontinued operations and certain historical, non-coal producing operations. In connection with such matters, we arethe Company is required to assess the likelihood of any adverse judgments or outcomes, as well as potential ranges of probable losses.
A determination of the amount of reserves required for these matters is made after considerable analysis of each individual issue. We accruePeabody accrues for legal and environmental matters within “Operating costs and expenses” when it is probable that a liability has been incurred and the amount of the loss can be reasonably estimated. We provideIf a range of possible loss exists and no anticipated loss within the range is more likely than any other anticipated loss, the Company records the accrual at the low end of the range, in accordance with Accounting Standards Codification 450, “Contingencies.”
| Peabody Energy Corporation | 2022 Form 10-K | 82 | ||||||
Peabody provides disclosure surrounding loss contingencies when we believeit believes that it is at least reasonably possible that a material loss may be incurred or an exposure to loss in excess of amounts already accrued may exist. Adjustments to contingent liabilities are made when additional information becomes available that affects the amount of estimated loss, which information may include changes in facts and circumstances, changes in interpretations of law in the relevant courts, the results of new or updated environmental remediation cost studies and the ongoing consideration of trends in environmental remediation costs.
Accrued contingent liabilities exclude claims against third parties and are not discounted. The current portion of these accruals is included in “Accounts payables and accrued expenses” and the long-term portion is included in “Other noncurrent liabilities” in ourthe Company’s consolidated balance sheets. In general, legal fees related to environmental remediation and litigation are charged to expense. We includeThe Company includes the interest component of any litigation-related penalties within “Interest expense” in ourits consolidated statements of operations. See Note 26.21. “Commitments and Contingencies” to the accompanying consolidated financial statements for further discussion of ourthe Company’s contingent liabilities.
Newly Adopted Accounting Standards and Accounting Standards Not Yet Implemented
See Note 1. “Summary of Significant Accounting Policies” to the accompanying consolidated financial statements for a discussion of newly adopted accounting standards and accounting standards not yet implemented.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
The potential for changes in the market value of ourthe Company’s coal and freight-related trading, crude oil, diesel fuel natural gas and foreign currency contract portfolios, as applicable, is referred to as “market risk.” Market risk related to ourits coal trading and freight-related contract portfolio, which includes bilaterally-settled and over-the-counter (OTC) exchange-settled trading, in addition to, from time to time, the brokered trading of coal, is evaluated using a value at risk (VaR) analysis. VaR analysis is not used to evaluate ourthe Company’s non-trading diesel fuel or foreign currency hedging portfolios, as applicable, or coal trading activities we employit employs in support of coal production (as discussed below). We attemptThe Company attempts to manage market price risks through diversification, controlling position sizes and executing hedging strategies. Due to a lack of quoted market prices and the long-term, illiquid nature of the positions, we havethe Company has not quantified market price risk related to ourits non-trading, long-term coal supply agreement portfolio.
Coal Trading Activities and Related Commodity Price Risk
Coal Price Risk Monitored Using VaR. We engagePeabody engages in direct and brokered trading of physical coal and freight-related commodities in OTC markets. These activities give rise to commodity price risk, which represents the potential loss that can be caused by an adverse change in the market value of a particular commitment. WePeabody actively measure, monitor, managemeasures, monitors, manages and hedgehedges market price risk due to current and anticipated trading activities to remain within risk limits prescribed by management. For example, we haveit has policies in place that limit the amount of market price risk, as measured by VaR, that wethe Company may assume at any point in time from ourits trading and brokerage activities.
| Peabody | ||
| Peabody Energy Corporation | 2022 Form 10-K | 83 | ||||||
VaR analysis allows usthe Company to aggregate market price risk across products in the portfolio, compare market price risk on a consistent basis and identify the drivers of risk and changes thereto over time. We usePeabody uses historical data to estimate price volatility as an input to VaR. Given ourits reliance on historical data, we believethe Company believes VaR is reasonably effective in characterizing market price risk exposures in markets in which there are not sudden fundamental changes or shifts in market conditions. Nonetheless, an inherent limitation of VaR is that past changes in market price risk factors may not produce accurate predictions of future market price risk. Due to that limitation, combined with the subjectivity in the choice of the liquidation period and reliance on historical data to calibrate ourits models, we performthe Company performs stress and scenario analyses as needed to estimate the impacts of market price changes on the value of the portfolio. Additionally, back-testing is regularly performed to monitor the effectiveness of ourits VaR measure. The results of these analyses are used to supplement the VaR methodology and identify additional market price-related risks.
During the year ended December 31, 2019,2022, the actual low, high and average VaR associated with the Company’s trading and brokerage function was $0.3$0.6 million, $4.3$23.0 million and $1.3$5.4 million, respectively.
Other Risk Exposures. WePeabody also use ouruses its coal trading and brokerage platform to support various coal production-related activities. These transactions may involve coal to be produced from ourits mines, coal sourcing arrangements with third-party mining companies, joint venture positions with producers or offtake agreements with producers. While the support activities (such as the forward sale of coal to be produced and/or purchased) may ultimately involve instruments sensitive to market price risk, the sourcing of coal in these arrangements does not involve market risk sensitive instruments and does not encompass the commodity price risks that we monitorthe Company monitors through VaR analysis, as discussed above.
Future Realization. As of December 31, 2019,2022, the total estimated future realization of the value of ourthe Company’s trading portfolio is expected to occur over 2020 and 2021.during 2023.
Credit and Nonperformance Risk
The fair values of ourPeabody’s derivative instruments utilized for corporate hedging and coal trading activities reflect adjustments for credit risk, as necessary. OurThe Company’s exposure is substantially with electric utilities, energy marketers, steel producers and nonfinancial trading houses. OurIts policy is to independently evaluate each counterparty’s creditworthiness prior to entering into transactions and to regularly monitor exposures. We manage ourPeabody manages its counterparty risk from ourits hedging activities related to foreign currency and fuel exposures, as applicable, through established credit standards, diversification of counterparties, utilization of investment grade commercial banks, adherence to established tenor limits based on counterparty creditworthiness and continual monitoring of that creditworthiness. If we engagethe Company engages in a transaction with a counterparty that does not meet ourits credit standards, we seekthe Company seeks to protect ourits position by requiring the counterparty to provide an appropriate credit enhancement. Also, when appropriate (as determined by ourits credit management function), we havePeabody has taken steps to reduce ourits exposure to customers or counterparties whose credit has deteriorated and who may pose a higher risk of failure to perform under their contractual obligations. These steps include obtaining letters of credit or cash collateral (margin), requiring prepayments for shipments or the creation of customer trust accounts held for ourPeabody’s benefit to serve as collateral in the event of a failure to pay or perform. To reduce ourits credit exposure related to trading and brokerage activities, we seekPeabody seeks to enter into netting agreements with counterparties that permit usit to offset asset and liability positions with such counterparties and, to the extent required, wePeabody will post or receive margin amounts associated with exchange-cleared and certain OTC positions. WePeabody also continually monitormonitors counterparty and contract nonperformance risk, if present, on a case-by-case basis.
| Peabody Energy Corporation | ||||||||
Foreign Currency Risk
As of December 31, 2022, the Company held coal derivative contracts related to a portion of its forecasted sales with an aggregate notional volume of 0.6 million tonnes. Such financial contracts may include futures, forwards and options. The notional volume is related predominantly to financial derivatives entered to support the profitability of the Wambo Underground Mine as part of a strategy to extend the mine’s life. All such tonnes will settle in 2023. The Newcastle thermal coal index was $398.50 per tonne on December 31, 2022, and the Company had posted $198 million of variation margin for the related derivative contracts at such date. A change in the Newcastle forward curve of $100 per tonne would increase or decrease the Company’s variation margin requirement by approximately $55 million and result in comparable unrealized gains or losses.
Diesel Fuel Hedges.Price Risk
Previously, wethe Company managed price risk of the diesel fuel used in ourits mining activities through the use of derivatives, primarily swaps. As of December 31, 2019, we2022, the Company did not have any diesel fuel derivative instruments in place. WeThe Company also managemanages the price risk of diesel fuel through the use of cost pass-through contactscontracts with certain customers.
Interest Rate Risk
| Peabody Energy Corporation | 2022 Form 10-K | 85 | ||||||
Item 8. Financial Statements and Supplementary Data.
See Part IV, Item 15. “Exhibits and Financial Statement Schedules” of this report for the information required by this Item 8, which information is incorporated by reference herein.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
Item 9A. Controls and Procedures.
Evaluation of Disclosure Controls and Procedures
Changes in Internal Control Over Financial Reporting
There have been no changes in ourPeabody’s internal control over financial reporting that occurred during the three months ended December 31, 20192022 that have materially affected, or are reasonably likely to materially affect, ourits internal control over financial reporting.
Management’s Report on Internal Control Over Financial Reporting
Management is responsible for maintaining and establishing adequate internal control over financial reporting. An evaluation of the effectiveness of the design and operation of ourthe Company’s internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act, as of the end of the period covered by this report was performed under the supervision and with the participation of management, including ourits Chief Executive Officer and Interim Chief Financial Officer. This evaluation is performed to determine if ourthe Company’s internal controls over financial reporting provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Because of inherent limitations, any system of internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management conducted an assessment of the effectiveness of ourthe Company’s internal control over financial reporting using the criteria set by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework (2013). Based on this assessment, management concluded that the Company’s internal control over financial reporting was effective to provide reasonable assurance that the desired control objectives were achieved as of December 31, 2019.2022.
| Peabody Energy Corporation | 2022 Form 10-K | 86 | ||||||
Peabody’s Independent Registered Public Accounting Firm, Ernst & Young LLP, has audited ourPeabody’s internal control over financial reporting, as stated in their unqualified opinion report included herein.
| /s/ | /s/ Mark A. Spurbeck | ||||||||||
President and Chief Executive Officer | Mark A. Spurbeck | ||||||||||
February 21, 2020
| Peabody Energy Corporation | ||||||||
To the StockholdersShareholders and the Board of Directors of Peabody Energy Corporation
Opinion on Internal Control overOver Financial Reporting
We have audited Peabody Energy Corporation’s internal control over financial reporting as of December 31, 2019,2022, based on criteria established in Internal Control-IntegratedControl—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, Peabody Energy Corporation (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019,2022, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of Peabody Energy Corporation as of December 31, 20192022 and 2018 (Successor),2021, the related consolidated statements of operations, comprehensive income (loss), changes in stockholders’ equity and cash flows for each of the yearthree years in the period ended December 31, 2019 and 2018 (Successor), the period from April 2, 2017 through December 31, 2017 (Successor), the period from January 1, 2017 through April 1, 2017 (Predecessor),2022, and the related notes and financial statement schedule listed in the Index at Item 15(a) (collectively referred to as the “consolidated financial statements”) of the Company, and our report dated February 21, 202024, 2023 expressed an unqualified opinion thereon.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control overOver Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.
Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control overOver Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ Ernst & Young, LLP
St. Louis, Missouri
| Peabody Energy Corporation | ||||||||
Item 9B. Other Information.
None.
Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections.
Not applicable.
PART III
Item 10.Directors, Executive Officers and Corporate Governance.
The information required by Item 401 of Regulation S-K is included under the caption Proposal I1 - “Election of Directors” in our 2020Peabody’s 2023 Proxy Statement and in Part I, Item 1. “Business” of this report under the caption “Information About Our Executive Officers.” The information required by Items 405, 406 and 407(c)(3), (d)(4) and (d)(5) of Regulation S-K is included under the captions “Stock Ownership,” “Corporate“Additional Information Concerning the Board of Directors - Corporate Governance - Code of Business Conduct and Ethics” and “Additional Information Concerning the Board of Directors - Committee Overview - Audit Committee” in our 2020Peabody’s 2023 Proxy Statement. Such information is incorporated herein by reference.
Item 11.Executive Compensation.
The information required by Items 402 and 407(e)(4) and (e)(5) of Regulation S-K is included under the captions “Additional Information Concerning the Board of Directors - Director Compensation,” “Compensation Discussion and Analysis,” “Compensation Committee Interlocks and Insider Participation” andParticipation,” “Compensation Committee Report”Report,” “Risk Assessment in our 2020Compensation Programs,” “Executive Compensation Tables,” “Pay Ratio Disclosure” and “Pay Versus Performance Disclosure” in Peabody’s 2023 Proxy Statement and is incorporated herein by reference.
Item 12.Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
The information required by Item 403 of Regulation S-K is included under the caption “Stock Ownership - Security Ownership of Directors and Management and Certain Beneficial Owners” in our 2020Peabody’s 2023 Proxy Statement and is incorporated herein by reference.
Equity Compensation Plan Information
As required by Item 201(d) of Regulation S-K, the following table provides information regarding ourPeabody’s equity compensation plans as of December 31, 2019:2022:
| (a) Number of Securities to be Issued upon Exercise of Outstanding Options, Warrants and Rights | Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights | Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column (a)) | ||||||||||||||||||
| Plan Category | ||||||||||||||||||||
| Equity compensation plans approved by security holders | 624,553 | (1) | $ | — | (2) | 6,907,901 | ||||||||||||||
| Equity compensation plans not approved by security holders | — | — | — | |||||||||||||||||
| Total | 624,553 | $ | — | 6,907,901 | ||||||||||||||||
(a) Number of Securities to be Issued upon Exercise of Outstanding Options, Warrants and Rights | Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights | Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column (a)) | ||||||||
| Plan Category | ||||||||||
| Equity compensation plans approved by security holders | 551,424 | (1) | $ | — | (2) | 8,877,949 | ||||
| Equity compensation plans not approved by security holders | — | — | — | |||||||
| Total | 551,424 | $ | — | 8,877,949 | ||||||
(2)The weighted-average exercise price shown in the table does not take into account outstanding deferred stock units or performance awards. |
Refer to Note 20.16. “Share-Based Compensation” to the accompanying consolidated financial statements for additional information regarding the material features of ourPeabody’s current equity compensation plans.
| Peabody Energy Corporation | 2022 Form 10-K | 89 | ||||||
Item 13.Certain Relationships and Related Transactions, and Director Independence.
The information required by Items 404 and 407(a) of Regulation S-K is included under the captions “Review of Related Person Transactions” and “Additional Information Concerning the Board of Directors - Board Independence” in our 2020Peabody’s 2023 Proxy Statement and is incorporated herein by reference.
Item 14.Principal Accountant Fees and Services.
The information required by Item 9(e) of Schedule 14A is included under the caption “Audit Fees” in our 2020Peabody’s 2023 Proxy Statement and is incorporated herein by reference.
PART IV
Item 15.Exhibits and Financial Statement Schedules.
(a) Documents Filed as Part of the Report
(1) Financial Statements.
The following consolidated financial statements of Peabody Energy Corporation and the report thereon of the independent registered public accounting firm are included herein on the pages indicated:
| Page | |||||
Report of Independent Registered Public Accounting Firm(PCAOB ID: 42) | F-1 | ||||
F-3 | |||||
F-4 | |||||
F-5 | |||||
F-6 | |||||
F-8 | |||||
F-9 | |||||
(2) Financial Statement Schedules.
The following financial statement schedule of Peabody Energy Corporation is at the page indicated:
| Page | |||||
F-63 | |||||
All other schedules for which provision is made in the applicable accounting regulation of the Securities and Exchange Commission are not required under the related instructions or are not applicable and, therefore, have been omitted.
(3) Exhibits.
| Exhibit No. | Description of Exhibit | ||||||||||
| 2.1 | |||||||||||
| 2.2 | |||||||||||
| Peabody Energy Corporation | 2022 Form 10-K | 90 | ||||||
| 2.3 | |||||||||||
| 2.4 | |||||||||||
| 3.1 | |||||||||||
| 3.2 | |||||||||||
| 4.1 | |||||||||||
| 4.2 | |||||||||||
| 4.3 | |||||||||||
| 4.4 | |||||||||||
| 4.5 | |||||||||||
| 4.6 | |||||||||||
| 4.7 | |||||||||||
| 4.8 | |||||||||||
| 4.9 | |||||||||||
| 4.10 | |||||||||||
| 4.11 | |||||||||||
| 4.12 | |||||||||||
| 4.13 | |||||||||||
| 4.14 | |||||||||||
| 10.1 | Federal Coal Lease WYW0321779: North Antelope/Rochelle Mine (Incorporated by reference to Exhibit 10.3 of the Registrant’s Form S-4 Registration Statement No. 333-59073, filed July 14, 1998). | ||||||||||
| 10.2 | Federal Coal Lease WYW119554: North Antelope/Rochelle Mine (Incorporated by reference to Exhibit 10.4 of the Registrant’s Form S-4 Registration Statement No. 333-59073, filed July 14, 1998). | ||||||||||
| 10.3 | Federal Coal Lease WYW5036: Rawhide Mine (Incorporated by reference to Exhibit 10.5 of the Registrant’s Form S-4 Registration Statement No. 333-59073, filed July 14, 1998). | ||||||||||
| Peabody Energy Corporation | 2022 Form 10-K | 91 | ||||||
| 10.4 | Federal Coal Lease WYW3397: Caballo Mine (Incorporated by reference to Exhibit 10.6 of the Registrant’s Form S-4 Registration Statement No. 333-59073, filed July 14, 1998). | ||||||||||
| 10.5 | Federal Coal Lease WYW83394: Caballo Mine (Incorporated by reference to Exhibit 10.7 of the Registrant’s Form S-4 Registration Statement No. 333-59073, filed July 14, 1998). | ||||||||||
| 10.6 | Federal Coal Lease WYW136142 (Incorporated by reference to Exhibit 10.8 of Amendment No. 1 to the Registrant’s Form S-4 Registration Statement No. 333-59073, filed September 8, 1998). | ||||||||||
| 10.7 | Royalty Prepayment Agreement by and among Peabody Natural Resources Company, Gallo Finance Company and Chaco Energy Company, dated September 30, 1998 (incorporated by reference to Exhibit 10.9 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 1998). | ||||||||||
| 10.8 | |||||||||||
| 10.9 | |||||||||||
| 10.10 | |||||||||||
| 10.11 | |||||||||||
| 10.12 | |||||||||||
| 10.13 | |||||||||||
| 10.14 | |||||||||||
| 10.15 | |||||||||||
| 10.16 | |||||||||||
| 10.17 | |||||||||||
| 10.18 | |||||||||||
| 10.19 | |||||||||||
| 10.20 | |||||||||||
| 10.21 | |||||||||||
| 10.22 | |||||||||||
| 10.23* | |||||||||||
| 10.24* | |||||||||||
| 10.25* | |||||||||||
| 10.26 | |||||||||||
| Peabody Energy Corporation | 2022 Form 10-K | 92 | ||||||
| 10.27 | |||||||||||
| 10.28 | |||||||||||
| 10.29 | |||||||||||
| 10.30 | |||||||||||
| 10.31 | |||||||||||
| 10.32 | |||||||||||
| 10.33 | |||||||||||
| 10.34 | |||||||||||
| 10.35 | |||||||||||
| 10.36 | |||||||||||
| 10.37 | |||||||||||
| 10.38 | |||||||||||
| 10.39 | |||||||||||
| Peabody Energy Corporation | 2022 Form 10-K | 93 | ||||||
| 10.40 | |||||||||||
| 10.41 | |||||||||||
| 10.42 | |||||||||||
| 10.43 | |||||||||||
| 10.44 | |||||||||||
| 10.45 | |||||||||||
| 10.46 | |||||||||||
| 10.47 | |||||||||||
| 10.48 | |||||||||||
| 10.49 | |||||||||||
| 10.50* | |||||||||||
| 10.51 | |||||||||||
| 10.52 | |||||||||||
| 10.53* | |||||||||||
| 10.54* | |||||||||||
| 10.55* | |||||||||||
| 10.56* | |||||||||||
| 10.57 | |||||||||||
| Peabody Energy Corporation | 2022 Form 10-K | 94 | ||||||
| 10.58* | |||||||||||
| 10.59* | |||||||||||
| 10.60* | |||||||||||
| 10.61* | |||||||||||
| 10.62* | |||||||||||
| 10.63* | |||||||||||
| 10.64* | |||||||||||
| 10.65* | |||||||||||
| 10.66* | |||||||||||
| 10.67* | |||||||||||
| 10.68* | |||||||||||
| 10.69* | |||||||||||
| 10.70* | |||||||||||
| 10.71* | |||||||||||
| 10.72* | |||||||||||
| 10.73* | |||||||||||
| 10.74 | |||||||||||
| 10.75 | |||||||||||
| 10.76 | |||||||||||
| Peabody Energy Corporation | 2022 Form 10-K | 95 | ||||||
| Peabody Energy Corporation | 2022 Form 10-K | 96 | ||||||
| 32.2† | |||||||||||
| 95† | |||||||||||
| 96.1 | |||||||||||
| 96.2 | |||||||||||
| 96.3 | |||||||||||
| 96.4 | |||||||||||
| 101.INS | Inline XBRL Instance Document - the instance document does not appear in the interactive data file because XBRL tags are embedded within the Inline XBRL document | ||||||||||
| 101.SCH | Inline XBRL Taxonomy Extension Schema Document | ||||||||||
| 101.CAL | Inline XBRL Taxonomy Extension Calculation Linkbase Document | ||||||||||
| 101.DEF | Inline XBRL Taxonomy Extension Definition Linkbase Document | ||||||||||
| 101.LAB | Inline XBRL Taxonomy Extension Label Linkbase Document | ||||||||||
| 101.PRE | Inline XBRL Taxonomy Extension Presentation Linkbase Document | ||||||||||
| 104 | Cover Page Interactive Data File (embedded within the Inline XBRL document). | ||||||||||
| * | These exhibits constitute all management contracts, compensatory plans and arrangements required to be filed as an exhibit to this form pursuant to Item 15(a)(3) and 15(b) of this report. | ||||||||||
| † | Filed herewith. | ||||||||||
Pursuant to the Instructions to Exhibits, certain instruments defining the rights of holders of long-term debt securities of the Company and its consolidated subsidiaries are not filed because the total amount of securities authorized under any such instrument does not exceed 10% of the total assets of the Company and its subsidiaries on a consolidated basis. A copy of such instrument will be furnished to the Securities and Exchange Commission upon request.
Item 16.Form 10-K Summary.
| Peabody Energy Corporation | ||||||||
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| PEABODY ENERGY CORPORATION | |||||
| /s/ | |||||
President and Chief Executive Officer | |||||
Date: February 21, 202024, 2023
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons, on behalf of the registrant and in the capacities and on the dates indicated.
| Signature | Title | Date | ||||||||||||||||||
| /s/ JAMES C. GRECH | President and Chief Executive Officer, Director (principal executive officer) | February 24, 2023 | ||||||||||||||||||
| James C. Grech | ||||||||||||||||||||
| /s/ MARK A. SPURBECK | Executive Vice President and Chief Financial Officer (principal financial and accounting officer) | February 24, 2023 | ||||||||||||||||||
| Mark A. Spurbeck | ||||||||||||||||||||
| /s/ SAMANTHA ALGAZE | Director | February 24, 2023 | ||||||||||||||||||
| Samantha Algaze | ||||||||||||||||||||
| /s/ ANDREA BERTONE | Director | February 24, 2023 | ||||||||||||||||||
| Andrea Bertone | ||||||||||||||||||||
| /s/ BILL CHAMPION | Director | February 24, 2023 | ||||||||||||||||||
| Bill Champion | ||||||||||||||||||||
| /s/ NICHOLAS CHIREKOS | Director | February | ||||||||||||||||||
| Nicholas Chirekos | ||||||||||||||||||||
| /s/ STEPHEN GORMAN | Director | February | ||||||||||||||||||
| Stephen Gorman | ||||||||||||||||||||
| /s/ JOE LAYMON | Director | February | ||||||||||||||||||
| Joe Laymon | ||||||||||||||||||||
| /s/ ROBERT MALONE | Chairman | February | ||||||||||||||||||
| Robert Malone | ||||||||||||||||||||
| /s/ DAVID MILLER | Director | February | ||||||||||||||||||
| David Miller | ||||||||||||||||||||
| Peabody Energy Corporation | ||||||||
To the StockholdersShareholders and the Board of Directors of Peabody Energy Corporation
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Peabody Energy Corporation (the Company) as of December 31, 20192022 and 2018 (Successor),2021, the related consolidated statements of operations, comprehensive income (loss), changes in stockholders’stockholders' equity and cash flows for each of the yearthree years in the period ended December 31, 2019 and 2018 (Successor), the period from April 2, 2017 through December 31, 2017 (Successor), and the period from January 1, 2017 through April 1, 2017 (Predecessor),2022, and the related notes and financial statement schedule listed in the Index at Item 15(a) (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 20192022 and 2018 (Successor),2021, and the results of its operations and its cash flows for each of the yearthree years in the period ended December 31, 2019 and 2018 (Successor), the period from April 2, 2017 through December 31, 2017 (Successor), and the period from January 1, 2017 through April 1, 2017 (Predecessor)2022, in conformity with USU.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’sCompany's internal control over financial reporting as of December 31, 2019,2022, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework), and our report dated February 21, 202024, 2023 expressed an unqualified opinion thereon.
Basis for Opinion
These financial statements are the responsibility of the Company’sCompany's management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures includeincluded examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit MattersMatter
The critical audit mattersmatter communicated below are mattersis a matter arising from the current period audit of the financial statements that werewas communicated or required to be communicated to the audit committee and that: (1) relaterelates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of the critical audit mattersmatter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit mattersmatter below, providing a separate opinion on the critical audit mattersmatter or on the accounts or disclosures to which they relate.
| Peabody Energy Corporation | ||||||||
| Asset Retirement Obligation Liability | |||||
| Description of the Matter | At December 31, Management’s estimate involves a high degree of subjectivity and auditing the significant assumptions utilized by management in estimating the amount of the liability requires judgment. In particular, the obligation is determined using a discounted cash flow technique | ||||
| How We Addressed the Matter in Our Audit | We obtained an understanding, evaluated the design, and tested the operating effectiveness of the controls over the Company’s accounting for ARO liabilities, including controls over management’s review of the ARO calculation and the significant assumptions and data inputs described above. To audit the ARO liabilities, our procedures included evaluating the methodology used, and testing the significant assumptions discussed above and the underlying data used by the Company in its estimate. We compared assumptions including the credit-adjusted risk-free rate and inflation rate to current market data. In addition, to assess the estimates of disturbed acreage, timing of reclamation activities, and reclamation costs, we evaluated significant changes from the prior estimate, | ||||
/s/ Ernst & Young, LLP
We have served as the Company’s auditor since 1991.
St. Louis, Missouri
February 21, 2020
| Peabody Energy Corporation | ||||||||
PEABODY ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
| Successor | Predecessor | |||||||||||||
| Year Ended December 31, 2019 | Year Ended December 31, 2018 | April 2 through December 31, 2017 | January 1 through April 1, 2017 | |||||||||||
| (Dollars in millions, except per share data) | ||||||||||||||
| Revenues | $ | 4,623.4 | $ | 5,581.8 | $ | 4,252.6 | $ | 1,326.2 | ||||||
| Costs and expenses | ||||||||||||||
| Operating costs and expenses (exclusive of items shown separately below) | 3,536.6 | 4,071.4 | 3,045.1 | 950.2 | ||||||||||
| Depreciation, depletion and amortization | 601.0 | 679.0 | 521.6 | 119.9 | ||||||||||
| Asset retirement obligation expenses | 58.4 | 53.0 | 41.2 | 14.6 | ||||||||||
| Selling and administrative expenses | 145.0 | 158.1 | 106.3 | 36.3 | ||||||||||
| Restructuring charges | 24.3 | 1.2 | 7.6 | — | ||||||||||
| Transaction costs related to business combinations and joint ventures | 21.6 | 7.4 | — | — | ||||||||||
| Other operating (income) loss: | ||||||||||||||
| Net gain on disposals | (2.1 | ) | (48.2 | ) | (84.0 | ) | (22.8 | ) | ||||||
| Gain on formation of United Wambo Joint Venture | (48.1 | ) | — | — | — | |||||||||
| Asset impairment | 270.2 | — | — | 30.5 | ||||||||||
| Provision for North Goonyella equipment loss | 83.2 | 66.4 | — | — | ||||||||||
| North Goonyella insurance recovery | (125.0 | ) | — | — | — | |||||||||
| Income from equity affiliates | (3.4 | ) | (68.1 | ) | (49.0 | ) | (15.0 | ) | ||||||
| Operating profit | 61.7 | 661.6 | 663.8 | 212.5 | ||||||||||
| Interest expense | 144.0 | 149.3 | 119.7 | 32.9 | ||||||||||
| Loss on early debt extinguishment | 0.2 | 2.0 | 20.9 | — | ||||||||||
| Interest income | (27.0 | ) | (33.6 | ) | (5.6 | ) | (2.7 | ) | ||||||
| Net periodic benefit costs, excluding service cost | 19.4 | 18.1 | 21.9 | 14.4 | ||||||||||
| Net mark-to-market adjustment on actuarially determined liabilities | 67.4 | (125.5 | ) | (45.2 | ) | — | ||||||||
| Reorganization items, net | — | (12.8 | ) | — | 627.2 | |||||||||
| (Loss) income from continuing operations before income taxes | (142.3 | ) | 664.1 | 552.1 | (459.3 | ) | ||||||||
| Income tax provision (benefit) | 46.0 | 18.4 | (161.0 | ) | (263.8 | ) | ||||||||
| (Loss) income from continuing operations, net of income taxes | (188.3 | ) | 645.7 | 713.1 | (195.5 | ) | ||||||||
| Income (loss) from discontinued operations, net of income taxes | 3.2 | 18.1 | (19.8 | ) | (16.2 | ) | ||||||||
| Net (loss) income | (185.1 | ) | 663.8 | 693.3 | (211.7 | ) | ||||||||
| Less: Series A Convertible Preferred Stock dividends | — | 102.5 | 179.5 | — | ||||||||||
| Less: Net income attributable to noncontrolling interests | 26.2 | 16.9 | 15.2 | 4.8 | ||||||||||
| Net (loss) income attributable to common stockholders | $ | (211.3 | ) | $ | 544.4 | $ | 498.6 | $ | (216.5 | ) | ||||
| (Loss) income from continuing operations: | ||||||||||||||
| Basic (loss) income per share | $ | (2.07 | ) | $ | 4.35 | $ | 3.85 | $ | (10.93 | ) | ||||
| Diluted (loss) income per share | $ | (2.07 | ) | $ | 4.28 | $ | 3.81 | $ | (10.93 | ) | ||||
| Net (loss) income attributable to common stockholders: | ||||||||||||||
| Basic (loss) income per share | $ | (2.04 | ) | $ | 4.50 | $ | 3.70 | $ | (11.81 | ) | ||||
| Diluted (loss) income per share | $ | (2.04 | ) | $ | 4.43 | $ | 3.67 | $ | (11.81 | ) | ||||
| Year Ended December 31, | |||||||||||||||||
| 2022 | 2021 | 2020 | |||||||||||||||
| (Dollars in millions, except per share data) | |||||||||||||||||
| Revenue | $ | 4,981.9 | $ | 3,318.3 | $ | 2,881.1 | |||||||||||
| Costs and expenses | |||||||||||||||||
| Operating costs and expenses (exclusive of items shown separately below) | 3,290.8 | 2,553.1 | 2,524.9 | ||||||||||||||
| Depreciation, depletion and amortization | 317.6 | 308.7 | 346.0 | ||||||||||||||
| Asset retirement obligation expenses | 49.4 | 44.7 | 45.7 | ||||||||||||||
| Selling and administrative expenses | 88.8 | 84.9 | 99.5 | ||||||||||||||
| Restructuring charges | 2.9 | 8.3 | 37.9 | ||||||||||||||
| Transaction costs related to joint ventures | — | — | 23.1 | ||||||||||||||
| Other operating (income) loss: | |||||||||||||||||
| Net gain on disposals | (29.2) | (31.5) | (15.2) | ||||||||||||||
| Asset impairment | 11.2 | — | 1,487.4 | ||||||||||||||
| (Income) loss from equity affiliates | (131.2) | (82.1) | 60.1 | ||||||||||||||
| Operating profit (loss) | 1,381.6 | 432.2 | (1,728.3) | ||||||||||||||
| Interest expense | 140.3 | 183.4 | 139.8 | ||||||||||||||
| Net loss (gain) on early debt extinguishment | 57.9 | (33.2) | — | ||||||||||||||
| Interest income | (18.4) | (6.5) | (9.4) | ||||||||||||||
| Net periodic benefit credit, excluding service cost | (49.0) | (38.3) | (1.8) | ||||||||||||||
| Net mark-to-market adjustment on actuarially determined liabilities | (27.8) | (43.4) | (5.1) | ||||||||||||||
| Income (loss) from continuing operations before income taxes | 1,278.6 | 370.2 | (1,851.8) | ||||||||||||||
| Income tax (benefit) provision | (38.8) | 22.8 | 8.0 | ||||||||||||||
| Income (loss) from continuing operations, net of income taxes | 1,317.4 | 347.4 | (1,859.8) | ||||||||||||||
| Income (loss) from discontinued operations, net of income taxes | 1.7 | 24.0 | (14.0) | ||||||||||||||
| Net income (loss) | 1,319.1 | 371.4 | (1,873.8) | ||||||||||||||
| Less: Net income (loss) attributable to noncontrolling interests | 22.0 | 11.3 | (3.5) | ||||||||||||||
| Net income (loss) attributable to common stockholders | $ | 1,297.1 | $ | 360.1 | $ | (1,870.3) | |||||||||||
| Income (loss) from continuing operations: | |||||||||||||||||
| Basic income (loss) per share | $ | 9.12 | $ | 3.03 | $ | (18.99) | |||||||||||
| Diluted income (loss) per share | $ | 8.29 | $ | 3.00 | $ | (18.99) | |||||||||||
| Net income (loss) attributable to common stockholders: | |||||||||||||||||
| Basic income (loss) per share | $ | 9.13 | $ | 3.24 | $ | (19.14) | |||||||||||
| Diluted income (loss) per share | $ | 8.31 | $ | 3.22 | $ | (19.14) | |||||||||||
See accompanying notes to consolidated financial statements
| Peabody Energy Corporation | ||||||||
PEABODY ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) INCOME
| Successor | Predecessor | |||||||||||||
| Year Ended December 31, 2019 | Year Ended December 31, 2018 | April 2 through December 31, 2017 | January 1 through April 1, 2017 | |||||||||||
| (Dollars in millions) | ||||||||||||||
| Net (loss) income | $ | (185.1 | ) | $ | 663.8 | $ | 693.3 | $ | (211.7 | ) | ||||
| Reclassification for realized losses on cash flow hedges (net of respective net tax provision of $0.0, $0.0, $0.0, and $9.1) included in net (loss) income | — | — | — | 18.6 | ||||||||||
| Postretirement plans and workers’ compensation obligations (net of respective net tax provision of $0.0, $7.1, $0.0, and $2.5) | (8.7 | ) | 44.6 | — | 4.4 | |||||||||
| Foreign currency translation adjustment | 0.2 | (5.9 | ) | 1.4 | 5.5 | |||||||||
| Other comprehensive (loss) income, net of income taxes | (8.5 | ) | 38.7 | 1.4 | 28.5 | |||||||||
| Comprehensive (loss) income | (193.6 | ) | 702.5 | 694.7 | (183.2 | ) | ||||||||
| Less: Series A Convertible Preferred Stock dividends | — | 102.5 | 179.5 | — | ||||||||||
| Less: Net income attributable to noncontrolling interests | 26.2 | 16.9 | 15.2 | 4.8 | ||||||||||
| Comprehensive (loss) income attributable to common stockholders | $ | (219.8 | ) | $ | 583.1 | $ | 500.0 | $ | (188.0 | ) | ||||
| Year Ended December 31, | |||||||||||||||||
| 2022 | 2021 | 2020 | |||||||||||||||
| (Dollars in millions) | |||||||||||||||||
| Net income (loss) | $ | 1,319.1 | $ | 371.4 | $ | (1,873.8) | |||||||||||
| Postretirement plans (net of $0.0 tax provisions in each period) | (53.8) | 93.1 | 168.1 | ||||||||||||||
| Foreign currency translation adjustment | (1.6) | (1.0) | 6.1 | ||||||||||||||
| Other comprehensive (loss) income, net of income taxes | (55.4) | 92.1 | 174.2 | ||||||||||||||
| Comprehensive income (loss) | 1,263.7 | 463.5 | (1,699.6) | ||||||||||||||
| Less: Net income (loss) attributable to noncontrolling interests | 22.0 | 11.3 | (3.5) | ||||||||||||||
| Comprehensive income (loss) attributable to common stockholders | $ | 1,241.7 | $ | 452.2 | $ | (1,696.1) | |||||||||||
See accompanying notes to consolidated financial statements
| Peabody Energy Corporation | ||||||||
PEABODY ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
| December 31, | December 31, | |||||||||||||||||
| 2019 | 2018 | 2022 | 2021 | |||||||||||||||
| (Amounts in millions, except per share data) | (Amounts in millions, except per share data) | |||||||||||||||||
| ASSETS | ASSETS | |||||||||||||||||
| Current assets | Current assets | |||||||||||||||||
| Cash and cash equivalents | $ | 732.2 | $ | 981.9 | Cash and cash equivalents | $ | 1,307.3 | $ | 954.3 | |||||||||
| Accounts receivable, net of allowance for doubtful accounts of $0.0 at December 31, 2019 and $4.4 at December 31, 2018 | 329.5 | 450.4 | ||||||||||||||||
| Inventories | 331.5 | 280.2 | ||||||||||||||||
| Accounts receivable, net of allowance for credit losses of $0.0 at December 31, 2022 and 2021 | Accounts receivable, net of allowance for credit losses of $0.0 at December 31, 2022 and 2021 | 465.5 | 350.5 | |||||||||||||||
| Inventories, net | Inventories, net | 296.1 | 226.7 | |||||||||||||||
| Other current assets | 220.7 | 243.1 | Other current assets | 303.6 | 270.2 | |||||||||||||
| Total current assets | 1,613.9 | 1,955.6 | Total current assets | 2,372.5 | 1,801.7 | |||||||||||||
| Property, plant, equipment and mine development, net | 4,679.1 | 5,207.0 | Property, plant, equipment and mine development, net | 2,865.0 | 2,950.6 | |||||||||||||
| Operating lease right-of-use assets | 82.4 | — | Operating lease right-of-use assets | 26.9 | 35.5 | |||||||||||||
| Restricted cash and collateral arrangements | Restricted cash and collateral arrangements | 187.4 | 23.8 | |||||||||||||||
| Investments and other assets | 139.1 | 212.6 | Investments and other assets | 84.3 | 138.2 | |||||||||||||
| Deferred income taxes | 28.3 | 48.5 | Deferred income taxes | 74.7 | — | |||||||||||||
| Total assets | $ | 6,542.8 | $ | 7,423.7 | Total assets | $ | 5,610.8 | $ | 4,949.8 | |||||||||
| LIABILITIES AND STOCKHOLDERS’ EQUITY | LIABILITIES AND STOCKHOLDERS’ EQUITY | |||||||||||||||||
| Current liabilities | Current liabilities | |||||||||||||||||
| Current portion of long-term debt | $ | 18.3 | $ | 36.5 | Current portion of long-term debt | $ | 13.2 | $ | 59.6 | |||||||||
| Accounts payable and accrued expenses | 957.0 | 1,022.0 | Accounts payable and accrued expenses | 905.5 | 872.1 | |||||||||||||
| Total current liabilities | 975.3 | 1,058.5 | Total current liabilities | 918.7 | 931.7 | |||||||||||||
| Long-term debt, less current portion | 1,292.5 | 1,330.5 | Long-term debt, less current portion | 320.6 | 1,078.2 | |||||||||||||
| Deferred income taxes | 28.8 | 9.7 | Deferred income taxes | 20.4 | 27.3 | |||||||||||||
| Asset retirement obligations | 654.1 | 686.4 | Asset retirement obligations | 665.8 | 654.8 | |||||||||||||
| Accrued postretirement benefit costs | 593.4 | 547.7 | Accrued postretirement benefit costs | 156.5 | 212.1 | |||||||||||||
| Operating lease liabilities, less current portion | 52.8 | — | Operating lease liabilities, less current portion | 11.0 | 27.2 | |||||||||||||
| Other noncurrent liabilities | 273.4 | 339.3 | Other noncurrent liabilities | 223.0 | 197.7 | |||||||||||||
| Total liabilities | 3,870.3 | 3,972.1 | Total liabilities | 2,316.0 | 3,129.0 | |||||||||||||
| Stockholders’ equity | Stockholders’ equity | |||||||||||||||||
| Preferred Stock — $0.01 per share par value; 100.0 shares authorized, no shares issued or outstanding as of December 31, 2019 or December 31, 2018 | — | — | ||||||||||||||||
| Series Common Stock — $0.01 per share par value; 50.0 shares authorized, no shares issued or outstanding as of December 31, 2019 or December 31, 2018 | — | — | ||||||||||||||||
| Common Stock — $0.01 per share par value; 450.0 shares authorized, 139.2 shares issued and 96.9 shares outstanding as of December 31, 2019 and 137.7 shares issued and 110.4 shares outstanding as of December 31, 2018 | 1.4 | 1.4 | ||||||||||||||||
| Preferred Stock — $0.01 per share par value; 100.0 shares authorized, no shares issued or outstanding as of December 31, 2022 or 2021 | Preferred Stock — $0.01 per share par value; 100.0 shares authorized, no shares issued or outstanding as of December 31, 2022 or 2021 | — | — | |||||||||||||||
| Series Common Stock — $0.01 per share par value; 50.0 shares authorized, no shares issued or outstanding as of December 31, 2022 or 2021 | Series Common Stock — $0.01 per share par value; 50.0 shares authorized, no shares issued or outstanding as of December 31, 2022 or 2021 | — | — | |||||||||||||||
| Common Stock — $0.01 per share par value; 450.0 shares authorized, 187.1 shares issued and 143.9 shares outstanding as of December 31, 2022 and 176.3 shares issued and 133.3 shares outstanding as of December 31, 2021 | Common Stock — $0.01 per share par value; 450.0 shares authorized, 187.1 shares issued and 143.9 shares outstanding as of December 31, 2022 and 176.3 shares issued and 133.3 shares outstanding as of December 31, 2021 | 1.9 | 1.8 | |||||||||||||||
| Additional paid-in capital | 3,351.1 | 3,304.7 | Additional paid-in capital | 3,975.9 | 3,745.6 | |||||||||||||
| Treasury stock, at cost — 42.3 and 27.3 common shares as of December 31, 2019 and December 31, 2018 | (1,367.3 | ) | (1,025.1 | ) | ||||||||||||||
| Retained earnings | 597.0 | 1,074.5 | ||||||||||||||||
| Treasury stock, at cost — 43.2 and 43.0 common shares as of December 31, 2022 and 2021 | Treasury stock, at cost — 43.2 and 43.0 common shares as of December 31, 2022 and 2021 | (1,372.9) | (1,370.3) | |||||||||||||||
| Retained earnings (accumulated deficit) | Retained earnings (accumulated deficit) | 383.9 | (913.2) | |||||||||||||||
| Accumulated other comprehensive income | 31.6 | 40.1 | Accumulated other comprehensive income | 242.5 | 297.9 | |||||||||||||
| Peabody Energy Corporation stockholders’ equity | 2,613.8 | 3,395.6 | Peabody Energy Corporation stockholders’ equity | 3,231.3 | 1,761.8 | |||||||||||||
| Noncontrolling interests | 58.7 | 56.0 | Noncontrolling interests | 63.5 | 59.0 | |||||||||||||
| Total stockholders’ equity | 2,672.5 | 3,451.6 | Total stockholders’ equity | 3,294.8 | 1,820.8 | |||||||||||||
| Total liabilities and stockholders’ equity | $ | 6,542.8 | $ | 7,423.7 | Total liabilities and stockholders’ equity | $ | 5,610.8 | $ | 4,949.8 | |||||||||
See accompanying notes to consolidated financial statements
| Peabody Energy Corporation | ||||||||
PEABODY ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
| Successor | Predecessor | Year Ended December 31, | |||||||||||||||||||||||||||||
| Year Ended December 31, 2019 | Year Ended December 31, 2018 | April 2 through December 31, 2017 | January 1 through April 1, 2017 | 2022 | 2021 | 2020 | |||||||||||||||||||||||||
| (Dollars in millions) | (Dollars in millions) | ||||||||||||||||||||||||||||||
| Cash Flows From Operating Activities | Cash Flows From Operating Activities | ||||||||||||||||||||||||||||||
| Net (loss) income | $ | (185.1 | ) | $ | 663.8 | $ | 693.3 | $ | (211.7 | ) | |||||||||||||||||||||
| Net income (loss) | Net income (loss) | $ | 1,319.1 | $ | 371.4 | $ | (1,873.8) | ||||||||||||||||||||||||
| (Income) loss from discontinued operations, net of income taxes | (3.2 | ) | (18.1 | ) | 19.8 | 16.2 | (Income) loss from discontinued operations, net of income taxes | (1.7) | (24.0) | 14.0 | |||||||||||||||||||||
| (Loss) income from continuing operations, net of income taxes | (188.3 | ) | 645.7 | 713.1 | (195.5 | ) | |||||||||||||||||||||||||
| Adjustments to reconcile (loss) income from continuing operations, net of income taxes to net cash provided by (used in) operating activities: | |||||||||||||||||||||||||||||||
| Income (loss) from continuing operations, net of income taxes | Income (loss) from continuing operations, net of income taxes | 1,317.4 | 347.4 | (1,859.8) | |||||||||||||||||||||||||||
| Adjustments to reconcile income (loss) from continuing operations, net of income taxes to net cash provided by (used in) operating activities: | Adjustments to reconcile income (loss) from continuing operations, net of income taxes to net cash provided by (used in) operating activities: | ||||||||||||||||||||||||||||||
| Depreciation, depletion and amortization | 601.0 | 679.0 | 521.6 | 119.9 | Depreciation, depletion and amortization | 317.6 | 308.7 | 346.0 | |||||||||||||||||||||||
| Fresh start noncash coal inventory revaluation | — | — | 67.3 | — | |||||||||||||||||||||||||||
| Noncash interest expense including loss on early extinguishment of debt | 16.2 | 19.2 | 34.0 | 0.5 | |||||||||||||||||||||||||||
| Noncash interest expense, net | Noncash interest expense, net | 17.7 | 21.3 | 16.2 | |||||||||||||||||||||||||||
| Deferred income taxes | 39.4 | 35.5 | (99.6 | ) | (262.3 | ) | Deferred income taxes | (81.6) | (7.5) | 27.8 | |||||||||||||||||||||
| Noncash share-based compensation | 38.3 | 34.9 | 21.8 | 1.9 | Noncash share-based compensation | 8.4 | 10.0 | 13.5 | |||||||||||||||||||||||
| Asset impairment | 270.2 | — | — | 30.5 | Asset impairment | 11.2 | — | 1,487.4 | |||||||||||||||||||||||
| Net gain on disposals | (2.1 | ) | (48.2 | ) | (84.0 | ) | (22.8 | ) | Net gain on disposals | (29.2) | (31.5) | (15.2) | |||||||||||||||||||
| Income from equity affiliates | (3.4 | ) | (68.1 | ) | (49.0 | ) | (15.0 | ) | |||||||||||||||||||||||
| Provision for North Goonyella equipment loss | 83.2 | 66.4 | — | — | |||||||||||||||||||||||||||
| Gain on formation of United Wambo Joint Venture | (48.1 | ) | — | — | — | ||||||||||||||||||||||||||
| Net loss (gain) on early debt extinguishment | Net loss (gain) on early debt extinguishment | 57.9 | (33.2) | — | |||||||||||||||||||||||||||
| (Income) loss from equity affiliates | (Income) loss from equity affiliates | (131.2) | (82.1) | 60.1 | |||||||||||||||||||||||||||
| Foreign currency option contracts | 5.2 | 9.1 | (0.8 | ) | — | Foreign currency option contracts | 2.3 | 5.8 | (13.0) | ||||||||||||||||||||||
| Reclassification from other comprehensive earnings for terminated hedge contracts | — | — | — | 27.6 | |||||||||||||||||||||||||||
| Noncash reorganization items, net | — | (12.8 | ) | — | (485.4 | ) | |||||||||||||||||||||||||
| Changes in current assets and liabilities: | Changes in current assets and liabilities: | ||||||||||||||||||||||||||||||
| Accounts receivable | 82.9 | 171.8 | (240.1 | ) | 159.3 | Accounts receivable | (115.0) | (105.6) | 84.6 | ||||||||||||||||||||||
| Inventories | (53.3 | ) | 50.2 | (36.8 | ) | (47.2 | ) | Inventories | (69.4) | 35.0 | 69.9 | ||||||||||||||||||||
| Other current assets | (35.6 | ) | (30.6 | ) | (53.1 | ) | 0.2 | Other current assets | (29.3) | (57.6) | 21.0 | ||||||||||||||||||||
| Accounts payable and accrued expenses | (118.2 | ) | (160.2 | ) | (158.5 | ) | (65.5 | ) | Accounts payable and accrued expenses | 68.0 | 128.1 | (192.4) | |||||||||||||||||||
| Collateral arrangements | — | 323.1 | 288.3 | (66.4 | ) | Collateral arrangements | (53.3) | (6.3) | (15.0) | ||||||||||||||||||||||
| Asset retirement obligations | 6.6 | 5.7 | 12.1 | 10.2 | Asset retirement obligations | (22.3) | 6.8 | 22.5 | |||||||||||||||||||||||
| Workers’ compensation obligations | 5.0 | (1.8 | ) | (1.1 | ) | (3.1 | ) | Workers’ compensation obligations | (0.9) | (2.0) | 1.8 | ||||||||||||||||||||
| Postretirement benefit obligations | 36.8 | (151.1 | ) | (19.8 | ) | 0.8 | Postretirement benefit obligations | (109.3) | (108.2) | (12.1) | |||||||||||||||||||||
| Pension obligations | (32.5 | ) | (66.9 | ) | (55.4 | ) | 5.4 | Pension obligations | 18.6 | 11.6 | (28.4) | ||||||||||||||||||||
| Take-or-pay obligation settlement | — | — | — | (5.5 | ) | ||||||||||||||||||||||||||
| Other, net | 2.1 | 16.0 | (27.8 | ) | 7.6 | Other, net | 2.7 | — | 0.1 | ||||||||||||||||||||||
| Net cash provided by (used in) continuing operations | 705.4 | 1,516.9 | 832.2 | (804.8 | ) | ||||||||||||||||||||||||||
| Net cash provided by continuing operations | Net cash provided by continuing operations | 1,180.3 | 440.7 | 15.0 | |||||||||||||||||||||||||||
| Net cash used in discontinued operations | (28.0 | ) | (27.2 | ) | (18.8 | ) | (8.2 | ) | Net cash used in discontinued operations | (6.7) | (20.7) | (24.7) | |||||||||||||||||||
| Net cash provided by (used in) operating activities | 677.4 | 1,489.7 | 813.4 | (813.0 | ) | Net cash provided by (used in) operating activities | 1,173.6 | 420.0 | (9.7) | ||||||||||||||||||||||
See accompanying notes to consolidated financial statements
| Peabody Energy Corporation | ||||||||
PEABODY ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS - (Continued)
| Successor | Predecessor | Year Ended December 31, | |||||||||||||||||||||||||||||
| Year Ended December 31, 2019 | Year Ended December 31, 2018 | April 2 through December 31, 2017 | January 1 through April 1, 2017 | 2022 | 2021 | 2020 | |||||||||||||||||||||||||
| (Dollars in millions) | (Dollars in millions) | ||||||||||||||||||||||||||||||
| Cash Flows From Investing Activities | Cash Flows From Investing Activities | ||||||||||||||||||||||||||||||
| Additions to property, plant, equipment and mine development | (285.4 | ) | (301.0 | ) | (166.6 | ) | (32.8 | ) | Additions to property, plant, equipment and mine development | (221.5) | (183.1) | (191.4) | |||||||||||||||||||
| Changes in accrued expenses related to capital expenditures | 0.1 | 0.1 | 16.2 | (1.4 | ) | Changes in accrued expenses related to capital expenditures | (2.7) | 7.4 | (6.1) | ||||||||||||||||||||||
| Federal coal lease expenditures | — | (0.5 | ) | — | (0.5 | ) | |||||||||||||||||||||||||
| Insurance proceeds attributable to North Goonyella equipment losses | 23.2 | — | — | — | |||||||||||||||||||||||||||
| Proceeds from disposal of assets, net of receivables | 30.0 | 76.4 | 17.9 | 24.3 | Proceeds from disposal of assets, net of receivables | 40.6 | 17.8 | 27.1 | |||||||||||||||||||||||
| Amount attributable to acquisition of Shoal Creek Mine | (2.4 | ) | (387.4 | ) | — | — | |||||||||||||||||||||||||
| Contributions to joint ventures | (419.1 | ) | (475.3 | ) | (305.8 | ) | (95.4 | ) | Contributions to joint ventures | (645.9) | (485.6) | (343.0) | |||||||||||||||||||
| Distributions from joint ventures | 408.8 | 483.7 | 307.0 | 90.5 | Distributions from joint ventures | 631.6 | 470.8 | 330.3 | |||||||||||||||||||||||
| Advances to related parties | (27.3 | ) | (13.8 | ) | (3.0 | ) | (0.4 | ) | Advances to related parties | (1.5) | (0.5) | (23.2) | |||||||||||||||||||
| Cash receipts from Middlemount Coal Pty Ltd | 14.7 | 106.7 | 48.1 | 32.7 | |||||||||||||||||||||||||||
| Investment in equity securities | (3.0 | ) | (10.0 | ) | — | — | |||||||||||||||||||||||||
| Cash receipts from Middlemount Coal Pty Ltd and other related parties | Cash receipts from Middlemount Coal Pty Ltd and other related parties | 171.8 | 44.7 | — | |||||||||||||||||||||||||||
| Other, net | (0.9 | ) | 3.8 | (7.2 | ) | (1.9 | ) | Other, net | (1.1) | (3.0) | (0.4) | ||||||||||||||||||||
| Net cash (used in) provided by investing activities | (261.3 | ) | (517.3 | ) | (93.4 | ) | 15.1 | ||||||||||||||||||||||||
| Net cash used in investing activities | Net cash used in investing activities | (28.7) | (131.5) | (206.7) | |||||||||||||||||||||||||||
| Cash Flows From Financing Activities | Cash Flows From Financing Activities | ||||||||||||||||||||||||||||||
| Proceeds from long-term debt | — | — | — | 1,000.0 | Proceeds from long-term debt | 545.0 | — | 375.0 | |||||||||||||||||||||||
| Repayments of long-term debt | (71.1 | ) | (85.0 | ) | (541.8 | ) | (2.1 | ) | Repayments of long-term debt | (1,407.4) | (285.3) | (169.5) | |||||||||||||||||||
| Payment of debt issuance and other deferred financing costs | (6.4 | ) | (21.2 | ) | (10.8 | ) | (45.4 | ) | Payment of debt issuance and other deferred financing costs | (21.1) | (22.5) | (7.0) | |||||||||||||||||||
| Common stock repurchases | (329.9 | ) | (834.7 | ) | (175.7 | ) | — | ||||||||||||||||||||||||
| Proceeds from common stock issuances, net of costs | Proceeds from common stock issuances, net of costs | 222.0 | 269.8 | — | |||||||||||||||||||||||||||
| Repurchase of employee common stock relinquished for tax withholding | (12.3 | ) | (14.5 | ) | (0.2 | ) | (0.1 | ) | Repurchase of employee common stock relinquished for tax withholding | (2.6) | (1.4) | (1.6) | |||||||||||||||||||
| Dividends paid | (258.1 | ) | (59.6 | ) | — | — | |||||||||||||||||||||||||
| Distributions to noncontrolling interests | (23.5 | ) | (10.3 | ) | (16.7 | ) | (0.1 | ) | Distributions to noncontrolling interests | (17.5) | (4.0) | (3.5) | |||||||||||||||||||
| Other, net | — | 0.1 | (0.2 | ) | — | ||||||||||||||||||||||||||
| Net cash (used in) provided by financing activities | (701.3 | ) | (1,025.2 | ) | (745.4 | ) | 952.3 | Net cash (used in) provided by financing activities | (681.6) | (43.4) | 193.4 | ||||||||||||||||||||
| Net change in cash, cash equivalents and restricted cash | (285.2 | ) | (52.8 | ) | (25.4 | ) | 154.4 | Net change in cash, cash equivalents and restricted cash | 463.3 | 245.1 | (23.0) | ||||||||||||||||||||
Cash, cash equivalents and restricted cash at beginning of period | 1,017.4 | 1,070.2 | 1,095.6 | 941.2 | 954.3 | 709.2 | 732.2 | ||||||||||||||||||||||||
Cash, cash equivalents and restricted cash at end of period | $ | 732.2 | $ | 1,017.4 | $ | 1,070.2 | $ | 1,095.6 | $ | 1,417.6 | $ | 954.3 | $ | 709.2 | |||||||||||||||||
(1) The following table provides a reconciliation of “Cash, cash equivalents and restricted cash at beginning of period”: | |||||||||||||||||||||||||||||||
(1) The following table provides a reconciliation of “Cash, cash equivalents and restricted cash at end of period” at December 31, 2022: | (1) The following table provides a reconciliation of “Cash, cash equivalents and restricted cash at end of period” at December 31, 2022: | ||||||||||||||||||||||||||||||
| Cash and cash equivalents | $ | 981.9 | Cash and cash equivalents | $ | 1,307.3 | ||||||||||||||||||||||||||
| Restricted cash included in “Investments and other assets” | 35.5 | ||||||||||||||||||||||||||||||
| Cash, cash equivalents and restricted cash at beginning of period | $ | 1,017.4 | |||||||||||||||||||||||||||||
(2) The following table provides a reconciliation of “Cash, cash equivalents and restricted cash at end of period”: | |||||||||||||||||||||||||||||||
| Cash and cash equivalents | $ | 732.2 | |||||||||||||||||||||||||||||
| Restricted cash included in “Investments and other assets” | — | ||||||||||||||||||||||||||||||
| Restricted cash included in “Restricted cash and collateral arrangements” | Restricted cash included in “Restricted cash and collateral arrangements” | 110.3 | |||||||||||||||||||||||||||||
| Cash, cash equivalents and restricted cash at end of period | $ | 732.2 | Cash, cash equivalents and restricted cash at end of period | $ | 1,417.6 | ||||||||||||||||||||||||||
See accompanying notes to consolidated financial statements
| Peabody Energy Corporation | ||||||||
PEABODY ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY
| Peabody Energy Corporation Stockholders’ Equity | |||||||||||||||||||||||||||||||
| Series A Convertible Preferred Stock | Common Stock | Additional Paid-in Capital | Treasury Stock | (Accumulated Deficit) Retained Earnings | Accumulated Other Comprehensive (Loss) Income | Noncontrolling Interests | Total Stockholders’ Equity | ||||||||||||||||||||||||
| (Dollars in millions) | |||||||||||||||||||||||||||||||
| December 31, 2016 - Predecessor | $ | — | $ | 0.2 | $ | 2,422.0 | $ | (371.8 | ) | $ | (1,399.5 | ) | $ | (477.0 | ) | $ | 7.6 | $ | 181.5 | ||||||||||||
| Net (loss) income | — | — | — | — | (216.5 | ) | — | 4.8 | (211.7 | ) | |||||||||||||||||||||
| Net realized losses on cash flow hedges (net of $9.1 net tax provision) | — | — | — | — | — | 18.6 | — | 18.6 | |||||||||||||||||||||||
| Postretirement plans and workers’ compensation obligations (net of $2.5 tax provision) | — | — | — | — | — | 4.4 | — | 4.4 | |||||||||||||||||||||||
| Foreign currency translation adjustment | — | — | — | — | — | 5.5 | — | 5.5 | |||||||||||||||||||||||
| Share-based compensation for equity-classified awards | — | — | 1.9 | — | — | — | — | 1.9 | |||||||||||||||||||||||
| Repurchase of employee common stock relinquished for tax withholding | — | — | — | (0.1 | ) | — | — | — | (0.1 | ) | |||||||||||||||||||||
| Distributions to noncontrolling interests | — | — | — | — | — | — | (0.1 | ) | (0.1 | ) | |||||||||||||||||||||
| Elimination of Predecessor equity | — | (0.2 | ) | (2,423.9 | ) | 371.9 | 1,616.0 | 448.5 | (12.3 | ) | — | ||||||||||||||||||||
| April 1, 2017 - Predecessor | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | |||||||||||||||
| Issuance of Successor equity | 1,305.4 | 0.7 | 1,774.9 | — | — | — | 50.9 | 3,131.9 | |||||||||||||||||||||||
| April 2, 2017 - Successor | $ | 1,305.4 | $ | 0.7 | $ | 1,774.9 | $ | — | $ | — | $ | — | $ | 50.9 | $ | 3,131.9 | |||||||||||||||
| Net income | — | — | — | — | 678.1 | — | 15.2 | 693.3 | |||||||||||||||||||||||
| Foreign currency translation adjustment | — | — | — | — | — | 1.4 | — | 1.4 | |||||||||||||||||||||||
| Warrant conversions | — | 0.1 | (0.1 | ) | — | — | — | — | — | ||||||||||||||||||||||
| Series A Convertible Preferred Stock conversions | (748.2 | ) | 0.2 | 796.7 | — | (48.7 | ) | — | — | — | |||||||||||||||||||||
| Series A Convertible Preferred Stock dividends | 18.8 | — | (3.0 | ) | — | (15.8 | ) | — | — | — | |||||||||||||||||||||
| Share-based compensation for equity-classified awards | — | — | 21.8 | — | — | — | — | 21.8 | |||||||||||||||||||||||
| Common stock repurchases | — | — | — | (175.7 | ) | — | — | — | (175.7 | ) | |||||||||||||||||||||
| Repurchase of employee common stock relinquished for tax withholding | — | — | — | (0.2 | ) | — | — | — | (0.2 | ) | |||||||||||||||||||||
| Distributions to noncontrolling interests | — | — | — | — | — | — | (16.7 | ) | (16.7 | ) | |||||||||||||||||||||
| December 31, 2017 - Successor | $ | 576.0 | $ | 1.0 | $ | 2,590.3 | $ | (175.9 | ) | $ | 613.6 | $ | 1.4 | $ | 49.4 | $ | 3,655.8 | ||||||||||||||
| Impact of adoption of Accounting Standards Update 2014-09 | — | — | — | — | (22.5 | ) | — | — | (22.5 | ) | |||||||||||||||||||||
| Net income | — | — | — | — | 646.9 | — | 16.9 | 663.8 | |||||||||||||||||||||||
| Dividends declared ($0.485 per share) | — | — | 1.4 | — | (61.0 | ) | — | — | (59.6 | ) | |||||||||||||||||||||
| Postretirement plans and workers’ compensation obligations (net of $7.1 tax provision) | — | — | — | — | — | 44.6 | — | 44.6 | |||||||||||||||||||||||
| Foreign currency translation adjustment | — | — | — | — | — | (5.9 | ) | — | (5.9 | ) | |||||||||||||||||||||
| Series A Convertible Preferred Stock conversions | (576.0 | ) | 0.4 | 678.1 | — | (102.5 | ) | — | — | — | |||||||||||||||||||||
| Share-based compensation for equity-classified awards | — | — | 34.9 | — | — | — | — | 34.9 | |||||||||||||||||||||||
| Common stock repurchases | — | — | — | (834.7 | ) | — | — | — | (834.7 | ) | |||||||||||||||||||||
| Repurchase of employee common stock relinquished for tax withholding | — | — | — | (14.5 | ) | — | — | — | (14.5 | ) | |||||||||||||||||||||
| Distributions to noncontrolling interests | — | — | — | — | — | — | (10.3 | ) | (10.3 | ) | |||||||||||||||||||||
| December 31, 2018 - Successor | $ | — | $ | 1.4 | $ | 3,304.7 | $ | (1,025.1 | ) | $ | 1,074.5 | $ | 40.1 | $ | 56.0 | $ | 3,451.6 | ||||||||||||||
| Net (loss) income | — | — | — | — | (211.3 | ) | — | 26.2 | (185.1 | ) | |||||||||||||||||||||
| Dividends declared ($2.410 per share) | — | — | 8.1 | — | (266.2 | ) | — | — | (258.1 | ) | |||||||||||||||||||||
| Postretirement plans and workers’ compensation obligations (net of $0.0 tax provision) | — | — | — | — | — | (8.7 | ) | — | (8.7 | ) | |||||||||||||||||||||
| Foreign currency translation adjustment | — | — | — | — | — | 0.2 | — | 0.2 | |||||||||||||||||||||||
| Share-based compensation for equity-classified awards | — | — | 38.3 | — | — | — | — | 38.3 | |||||||||||||||||||||||
| Common stock repurchases | — | — | — | (329.9 | ) | — | — | — | (329.9 | ) | |||||||||||||||||||||
| Repurchase of employee common stock relinquished for tax withholding | — | — | — | (12.3 | ) | — | — | — | (12.3 | ) | |||||||||||||||||||||
| Distributions to noncontrolling interests | — | — | — | — | — | — | (23.5 | ) | (23.5 | ) | |||||||||||||||||||||
| December 31, 2019 - Successor | $ | — | $ | 1.4 | $ | 3,351.1 | $ | (1,367.3 | ) | $ | 597.0 | $ | 31.6 | $ | 58.7 | $ | 2,672.5 | ||||||||||||||
| Peabody Energy Corporation Stockholders’ Equity | |||||||||||||||||||||||||||||||||||||||||||||||
| Common Stock | Additional Paid-in Capital | Treasury Stock | Retained Earnings (Accumulated Deficit) | Accumulated Other Comprehensive Income | Noncontrolling Interests | Total Stockholders’ Equity | |||||||||||||||||||||||||||||||||||||||||
| (Dollars in millions) | |||||||||||||||||||||||||||||||||||||||||||||||
| December 31, 2019 | $ | 1.4 | $ | 3,351.1 | $ | (1,367.3) | $ | 597.0 | $ | 31.6 | $ | 58.7 | $ | 2,672.5 | |||||||||||||||||||||||||||||||||
| Net loss | — | — | — | (1,870.3) | — | (3.5) | (1,873.8) | ||||||||||||||||||||||||||||||||||||||||
| Postretirement plans (net of $0.0 tax provision) | — | — | — | — | 168.1 | — | 168.1 | ||||||||||||||||||||||||||||||||||||||||
| Foreign currency translation adjustment | — | — | — | — | 6.1 | — | 6.1 | ||||||||||||||||||||||||||||||||||||||||
| Share-based compensation for equity-classified awards | — | 13.5 | — | — | — | — | 13.5 | ||||||||||||||||||||||||||||||||||||||||
| Repurchase of employee common stock relinquished for tax withholding | — | — | (1.6) | — | — | — | (1.6) | ||||||||||||||||||||||||||||||||||||||||
| Distributions to noncontrolling interests | — | — | — | — | — | (3.5) | (3.5) | ||||||||||||||||||||||||||||||||||||||||
| December 31, 2020 | $ | 1.4 | $ | 3,364.6 | $ | (1,368.9) | $ | (1,273.3) | $ | 205.8 | $ | 51.7 | $ | 981.3 | |||||||||||||||||||||||||||||||||
| Net income | — | — | — | 360.1 | — | 11.3 | 371.4 | ||||||||||||||||||||||||||||||||||||||||
| Postretirement plans (net of $0.0 tax provision) | — | — | — | — | 93.1 | — | 93.1 | ||||||||||||||||||||||||||||||||||||||||
| Foreign currency translation adjustment | — | — | — | — | (1.0) | — | (1.0) | ||||||||||||||||||||||||||||||||||||||||
| Share-based compensation for equity-classified awards | — | 10.0 | — | — | — | — | 10.0 | ||||||||||||||||||||||||||||||||||||||||
| Common stock issued in exchange for debt retirement | 0.1 | 101.8 | — | — | — | — | 101.9 | ||||||||||||||||||||||||||||||||||||||||
| Common stock issuances, net of cost | 0.3 | 269.2 | — | — | — | — | 269.5 | ||||||||||||||||||||||||||||||||||||||||
| Repurchase of employee common stock relinquished for tax withholding | — | — | (1.4) | — | — | — | (1.4) | ||||||||||||||||||||||||||||||||||||||||
| Distributions to noncontrolling interests | — | — | — | — | — | (4.0) | (4.0) | ||||||||||||||||||||||||||||||||||||||||
| December 31, 2021 | $ | 1.8 | $ | 3,745.6 | $ | (1,370.3) | $ | (913.2) | $ | 297.9 | $ | 59.0 | $ | 1,820.8 | |||||||||||||||||||||||||||||||||
| Net income | — | — | — | 1,297.1 | — | 22.0 | 1,319.1 | ||||||||||||||||||||||||||||||||||||||||
| Postretirement plans (net of $0.0 tax provision) | — | — | — | — | (53.8) | — | (53.8) | ||||||||||||||||||||||||||||||||||||||||
| Foreign currency translation adjustment | — | — | — | — | (1.6) | — | (1.6) | ||||||||||||||||||||||||||||||||||||||||
| Share-based compensation for equity-classified awards | — | 8.4 | — | — | — | — | 8.4 | ||||||||||||||||||||||||||||||||||||||||
| Common stock issuances, net of cost | 0.1 | 221.9 | — | — | — | — | 222.0 | ||||||||||||||||||||||||||||||||||||||||
| Repurchase of employee common stock relinquished for tax withholding | — | — | (2.6) | — | — | — | (2.6) | ||||||||||||||||||||||||||||||||||||||||
| Distributions to noncontrolling interests | — | — | — | — | — | (17.5) | (17.5) | ||||||||||||||||||||||||||||||||||||||||
| December 31, 2022 | $ | 1.9 | $ | 3,975.9 | $ | (1,372.9) | $ | 383.9 | $ | 242.5 | $ | 63.5 | $ | 3,294.8 | |||||||||||||||||||||||||||||||||
See accompanying notes to consolidated financial statements
| Peabody Energy Corporation | ||||||||
PEABODY ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) Summary of Significant Accounting Policies |
Basis of Presentation
The consolidated financial statements include the accounts of Peabody Energy Corporation (PEC) and its affiliates. The Company, or Peabody, are used interchangeably to refer to Peabody Energy Corporation, to Peabody Energy Corporation and its subsidiaries, or to such subsidiaries, as appropriate to the context. Interests in subsidiaries controlled by the Company are consolidated with any outside stockholder interests reflected as noncontrolling interests, except when the Company has an undivided interest in an unincorporated joint venture. In those cases, the Company includes its proportionate share in the assets, liabilities, revenuesrevenue and expenses of the jointly controlled entities within each applicable line item of the consolidated financial statements. All intercompany transactions, profits and balances have been eliminated in consolidation. Certain amounts from prior years have been reclassified to conform with the 2022 presentation.
Description of Business
The Company is engaged in the mining of thermal coal for sale primarily to electric utilities and metallurgical coal for sale to industrial customers. The Company’s mining operations are located in the United States (U.S.) and Australia, including an equity-affiliate mining operation in Australia. The Company also markets and brokers coal from other coal producers and trades coal and freight-related contracts through trading and business offices in the U.S., Australia, China and the United Kingdom.contracts. The Company’s other commercial activities include managing its coal reservereserves and resources and real estate holdings and supporting the development of clean coal technologies.
Adoption of ASU 2016-02 January 1, 2019 | |||
| (Dollars in millions) | |||
| ASSETS | |||
| Operating lease right-of-use assets | $ | 109.3 | |
| Total assets | $ | 109.3 | |
| LIABILITIES | |||
| Accounts payable and accrued expenses | $ | 41.8 | |
| Total current liabilities | 41.8 | ||
| Operating lease liabilities, less current portion | 67.5 | ||
| Total liabilities | $ | 109.3 | |
Accounting Standards Not Yet Implemented
| Peabody Energy Corporation | 2022 Form 10-K | F-9 | ||||||
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Revenue
The majority of the Company’s revenue is derived from the sale of coal under long-term coal supply agreements (those with initial terms of one year or longer and which often include price reopener and/or extension provisions) and contracts with terms of less than one year, including sales made on a spot basis. The Company’s revenue from coal sales is realized and earned when control passes to the customer. Under the typical terms of the Company’s coal supply agreements, title and risk of loss transfer to the customer at the mine or port, where coal is loaded to the transportation sources that serve the Company’s mines. The Company incurs certain “add-on” taxes and fees on coal sales. Reported coal sales include taxes and fees charged by various federal and state governmental bodies and the freight charged on destination customer contracts.
The Company’s seaborne operating platform is primarily export focused with customers spread across several countries, with a portion of the thermal and metallurgical coal sold within Australia. Generally, revenuesrevenue 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. A majority of these sales are executed through annual and multi-year international coal supply agreements that contain provisions requiring both parties to renegotiate pricing periodically. Industry commercial practice, and the Company’s typical practice, is to negotiate pricing for seaborne thermal coal contracts on an annual, spot or index basis and seaborne metallurgical coal contracts on a quarterly, spot or index basis. The portion of sales volume under contracts with a duration of less than one year has increased in recent years. In the case of periodically negotiated pricing, the Company may deliver coal under provisional pricing until a final agreed-upon price is determined. TheVariable consideration resulting make-whole settlements arefrom provisional pricing arrangements is recognized when reasonably estimable.based on the Company’s best estimate of the amount expected to be received at the time control is transferred to the customer.
The Company’s U.S. thermal operating platform primarily sells thermal coal to electric utilities in the U.S. under long-term contracts, with a portion sold into the seaborne markets as conditions warrant. A significant portion of the coal production from the U.S. thermal miningoperating segments is sold under existing long-term supply agreements, andagreements. Certain customers of those segments continue to pursueutilize long-term sales agreements in recognition of the importance of reliability, service and predictable coal prices to their operations. The terms of coal supply agreements result from competitive bidding and extensive negotiations with customers. Consequently, the terms of those agreements may vary 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.
Contract pricing is set forth on a per ton basis, and revenue is generally recorded as the product of price and volume delivered. 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. These contract prices may be adjusted based on inflation or deflation 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 sometimes experiences a reduction 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. Most of the coal supply agreements contain provisions requiring the Company to deliver coal meeting quality thresholds for certain characteristics such as Btu, sulfur content, ash content, 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 industry that restrict the use or type of coal permissible at the customer’s plant or increase the price of coal beyond specified limits.
Additional revenuesrevenue may include gains and losses related to mark-to-market adjustments from economic hedge activities intended to hedge future coal sales, revenuesrevenue from customer contract-related payments and other insignificant items including royalties related to coal lease agreements, sales agency commissions, farm income and property and facility rentals. Royalty income generally results from the lease or sublease of mineral rights to third parties, with payments based upon a percentage of the selling price or an amount per ton of coal produced.
| Peabody Energy Corporation | 2022 Form 10-K | F-10 | ||||||
Discontinued Operations
The Company classifies items within discontinued operations in the consolidated financial statements when the operations and cash flows of a particular component of the Company have been (or will be) eliminated from the ongoing operations of the Company as a result of a disposal (by sale or otherwise) and represents a strategic shift that has (or will have) a major effect on the entity’s operations and financial results.
Discontinued operations include certain former Seaborne Thermal Mining and Other U.S. Thermal Mining segment assets that have ceased production and other previously divested legacy operations, including Patriot Coal Corporation and certain of its wholly-owned subsidiaries (Patriot). In the third quarter of 2021, the Company executed the sale of the closed Wilkie Creek Mine, which reduced its closed mine reclamation liabilities and associated costs. Refer to Note 6. “Discontinued Operations”17. “Other Events” for additional details related to discontinued operations.information associated with the Company’s sale of the Wilkie Creek Mine.
Assets and Liabilities Held for Sale
The Company classifies assets and liabilities (disposal groups) to be sold as held for sale in the period in which all of the following criteria are met: management, having the authority to approve the action, commits to a plan to sell the disposal group; the disposal group is available for immediate sale in its present condition subject only to terms that are usual and customary for sales of such disposal groups; an active program to locate a buyer and other actions required to complete the plan to sell the disposal group have been initiated; the sale of the disposal group is probable, and transfer of the disposal group is expected to qualify for recognition as a completed sale within one year, except if events or circumstances beyond the Company's control extend the period of time required to sell the disposal group beyond one year; the disposal group is being actively marketed for sale at a price that is reasonable in relation to its current fair value; and actions required to complete the plan indicate that it is unlikely that significant changes to the plan will be made or that the plan will be withdrawn.
The Company initially measures a disposal group that is classified as held for sale at the lower of its carrying value or fair value less any costs to sell. Any loss resulting from this measurement is recognized in the period in which the held for sale criteria are met. Conversely, gains are not recognized on the sale of a disposal group until the date of sale. The Company assesses the fair value of a disposal group, less any costs to sell, each reporting period it remains classified as held for sale and reports any subsequent changes as an adjustment to the carrying value of the disposal group, as long as the new carrying value does not exceed the carrying value of the disposal group at the time it was initially classified as held for sale.
Upon determining that a disposal group meets the criteria to be classified as held for sale, the Company reports the assets and liabilities of the disposal group, if material, in the line items assets held for sale and liabilities held for sale in the consolidated balance sheets.
Cash and Cash Equivalents
Cash and cash equivalents are stated at cost, which approximates fair value. Cash equivalents consist of highly liquid investments with original maturities of three months or less.less.
Accounts Receivable
The timing of revenue recognition, billings and cash collections results in accounts receivable from customers. Customers are invoiced as coal is shipped or at periodic intervals in accordance with contractual terms. Invoices typically include customary adjustments for the resolution of price variability related to prior shipments, such as coal quality thresholds. Payments are generally received within thirty days of invoicing.
Inventories
Coal is reported as inventory at the point in time the coal is extracted from the mine. Raw coal represents coal stockpiles that may be sold in current condition or may be further processed prior to shipment to a customer. Saleable coal represents coal stockpiles which require no further processing prior to shipment to a customer.
Coal inventory is valued at the lower of average cost or net realizable value. Coal inventory costs include labor, supplies, equipment (including depreciation thereto) and operating overhead and other related costs incurred at or on behalf of the mining location. Net realizable value considers the projected future sales price of the particular coal product, less applicable selling costs and, in the case of raw coal, estimated remaining processing costs. The valuation of coal inventory is subject to several additional estimates, including those related to ground and aerial surveys used to measure quantities and processing recovery rates.
| Peabody Energy Corporation | 2022 Form 10-K | F-11 | ||||||
Materials and supplies inventory is valued at the lower of average cost or net realizable value, less a reserve for obsolete or surplus items. This reserve incorporates several factors, such as anticipated usage, inventory turnover and inventory levels.
Property, Plant, Equipment and Mine Development
Property, plant, equipment and mine development are recorded at cost. Interest costs applicable to major asset additions are capitalized during the construction period. There was 0no capitalized interest in any of the periods presented. Expenditures which extend the useful lives of existing plant and equipment assets are capitalized. Maintenance and repairs are charged to operating costs as incurred. Costs incurred to develop coal mines or to expand the capacity of operating mines are capitalized. Maintenance and repair costs incurred to maintain current production capacity at a mine are charged to operating costs as incurred. Costs to acquire computer hardware and the development and/or purchase of software for internal use are capitalized and depreciated over the estimated useful lives.
Coal reserves and resources are recorded at cost, or at fair value in the case of nonmonetary exchanges of reserves and resources or business acquisitions.
Depletion of coal reserves and resources and amortization of advance royalties are computed using the units-of-production method utilizing only proven and probable reservesexpected recoverable tons (as adjusted for recoverability factors) in the depletion base. Mine development costs are principally amortized over the estimated lives of the minesmine using the straight-line method. Depreciation of plant and equipment is computed using the straight-line method over the shorter of the asset’s estimated useful life or the life of the mine. TheAt December 31, 2022, the maximum estimated remaining life for any of the Company’s mines was 30 years. As such, the estimated useful lives by category of assets are as follows:
The Company leases coal reserves under agreements that require royalties to be paid as the coal is mined. Certain agreements also require minimum annual royalties to be paid regardless of the amount of coal mined during the year. Total royalty expense was $388.6$450.0 million, $474.3 million, $364.6$263.0 million and $115.2$214.7 million for the years ended December 31, 20192022, 2021 and 2018, and the periods April 2 through December 31, 2017 and January 1 through April 1, 2017,2020, respectively.
A substantial amount of the coal mined by the Company is produced from mineral reserves leased from the owner. One of the major lessors is the U.S. government, from which the Company leases substantially all of the coal it mines in Wyoming under terms set by Congress and administered by the U.S. Bureau of Land Management. These leases are generally for an initial term of ten years but may be extended by diligent development and mining of the reserves until all economically recoverable reserves are depleted. The Company has met the diligent development requirements for substantially all of these federal leases either directly through production, by including the lease as a part of a logical mining unit with other leases upon which development has occurred or by paying an advance royalty in lieu of continued operations. Annual production on these federal leases must total at least 1.0% of the leased reserve or the original amount of coal in the entire logical mining unit in which the leased reserve resides. In addition, royalties are payable monthly at a rate of 12.5% of the gross realization from the sale of the coal mined using surface mining methods and at a rate of 8.0% of the gross realization for coal produced using underground mining methods.
The remainder of the leased coal is generally leased from state governments, land holding companies and various individuals. The duration of these leases varies greatly. Typically, the lease terms are automatically extended as long as active mining continues. Royalty payments are generally based upon a specified rate per ton or a percentage of the gross realization from the sale of the coal.
Mining and exploration in Australia is generally conducted under leases, licenses or permits granted by the relevant state government. Mining and exploration licenses and their associated environmental protection approvals (granted by the state government, and in some cases also the federal government) contain conditions relating to such matters as minimum annual expenditures, environmental compliance, protection of flora and fauna, restoration and rehabilitation. Royalties are paid to the state government as a percentage of the sales price (less certain allowable deductions in some cases). Generally, landowners do not own the mineral rights or have the ability to grant rights to mine those minerals. These rights are retained by the state government. Compensation is often payable to landowners, occupiers and Aboriginal traditional owners with residual native title rights and interests for the loss of access to the land from the proposed mining activities. The amount and type of compensation and the ability to proceed to grant of a mining tenement may be determined by agreement or court determination, as provided by law.
| Peabody Energy Corporation | 2022 Form 10-K | F-12 | ||||||
Leases
The Company determines if an arrangement is a lease at inception. ROURight-of-use (ROU) assets represent the Company's right to use an underlying asset for the lease term and lease liabilities represent its obligation to make lease payments arising from the lease. Operating lease ROU assets and liabilities are recognized at the lease commencement date based on the present value of lease payments over the lease term. For the purpose of calculating such present values, lease payments include components that vary based upon an index or rate, using the prevailing index or rate at the commencement date, and exclude components that vary based upon other factors. As most of its leases do not contain a readily determinable implicit rate, the Company uses its incremental borrowing rate at commencement to determine the present value of lease payments. The Company does not separate lease components (i.e., fixed payments including rent, real estate taxes and insurance costs) from non-lease components (i.e., common-area maintenance) and recognizes them as a single lease component for the majority of asset classes. Variable lease payments not included within lease contracts are expensed as incurred. The Company's leases may include options to extend or terminate the lease, and such options are reflected in the term when their exercise is reasonably certain. Lease expense is recognized on a straight-line basis over the lease term.
For certain equipment leases, the Company applies a portfolio approach to effectively account for the operating lease ROU assets and liabilities.
Equity Investments
The Company applies the equity method to investments in joint ventures when it has the ability to exercise significant influence over the operating and financial policies of the joint venture. Investments accounted for under the equity method are initially recorded at cost and any difference between the cost of the Company’s investment and the underlying equity in the net assets of the joint venture at the investment date is amortized over the lives of the related assets that gave rise to the difference. The Company’s pro-rata share of the operating results of joint ventures and basis difference amortization is reported in the consolidated statements of operations in “Income“(Income) loss from equity affiliates.” Similarly, the Company’s pro-rata share of the cumulative foreign currency translation adjustment of its equity method investments whose functional currency is not the U.S. dollar is reported in the consolidated balance sheets as a component of “Accumulated other comprehensive income,” with periodic changes thereto reflected in the consolidated statements of comprehensive income. With respect to cash flows attributable to its equity investments, the Company applies the cumulative earnings approach, in which distributions received are considered returns on investment and are classified as cash inflows from operating activities unless the Company’s cumulative distributions received less distributions received in prior periods that were determined to be returns of investment exceed the cumulative equity in earnings recognized by the Company (as adjusted for amortization of basis differences). When such an excess occurs, current-period distributions up to this excess are considered returns of investment and are classified as cash inflows from investing activities.
The Company monitors its equity method investments for indicators that a decrease in investment value has occurred that is other than temporary. Examples of such indicators include a sustained history of operating losses and adverse changes in earnings and cash flow outlook. In the absence of quoted market prices for an investment, discounted cash flow projections are used to assess fair value, the underlying assumptions to which are generally considered unobservable Level 3 inputs under the fair value hierarchy. If the fair value of an investment is determined to be below its carrying value and that loss in fair value is deemed other than temporary, an impairment loss is recognized. NaNNo such impairment losses were recorded in any period presented.
For the remaining investments, the Company will adjust the carrying value of its investments to fair value based on observable market transactions. The Company also monitors such investments for indicators of impairment should no observable market transactions exist. Refer to Note 5.3. “Asset Impairment” for details regarding an impairment loss of $9.0$1.7 million recorded during the year ended December 31, 20192022 related to an investment in an equity security. NaNNo such impairment losses were recorded during the yearyears ended December 31, 20182021 or the periods April 2 through December 31, 2017 and January 1 through April 1, 2017.2020.
Asset Retirement Obligations
The Company’s asset retirement obligation (ARO) liabilities primarily consist of spending estimates for surface land reclamation and support facilities at both surface and underground mines in accordance with applicable reclamation laws and regulations in the U.S. and Australia as defined by each mining permit. Asset retirement obligations are determined for each mine using various estimates and assumptions including, among other items, estimates of disturbed acreage as determined from engineering data and estimates of future costs to reclaim the disturbed acreage.
| Peabody Energy Corporation | 2022 Form 10-K | F-13 | ||||||
The Company estimates its ARO liabilities for final reclamation and mine closure based upon detailed engineering calculations of the amount and timing of the future cash spending for a third party to perform the required work. Spending estimates are escalated for inflation and then discounted at the credit-adjusted, risk-free rate. The Company records an ARO asset associated with the discounted liability for final reclamation and mine closure. The obligation and corresponding asset are recognized in the period in which the liability is incurred. The ARO asset is amortized on the units-of-production method over its expected life and the ARO liability is accreted to the projected spending date. As changes in estimates occur (such as mine plan revisions, changes in estimated costs or changes in timing of the performance of reclamation activities), the revisions to the obligation and asset are recognized at the appropriate credit-adjusted, risk-free rate. The Company also recognizes an obligation for contemporaneous reclamation liabilities incurred as a result of surface mining. Contemporaneous reclamation consists primarily of grading, topsoil replacement and re-vegetation of backfilled pit areas.
Contingent Liabilities
From time to time, the Company is subject to legal and environmental matters related to its continuing and discontinued operations and certain historical, non-coal producing operations. In connection with such matters, the Company is required to assess the likelihood of any adverse judgments or outcomes, as well as potential ranges of probable losses.
A determination of the amount of reserves required for these matters is made after considerable analysis of each individual issue. The Company accrues for legal and environmental matters within “Operating costs and expenses” when it is probable that a liability has been incurred and the amount of the loss can be reasonably estimated. If a range of possible loss exists and no anticipated loss within the range is more likely than any other anticipated loss, the Company records the accrual at the low end of the range, in accordance with Accounting Standards Codification 450, “Contingencies.” The Company provides disclosure surrounding loss contingencies when it believes that it is at least reasonably possible that a material loss may be incurred or an exposure to loss in excess of amounts already accrued may exist. Adjustments to contingent liabilities are made when additional information becomes available that affects the amount of estimated loss, which information may include changes in facts and circumstances, changes in interpretations of law in the relevant courts, the results of new or updated environmental remediation cost studies and the ongoing consideration of trends in environmental remediation costs.
Accrued contingent liabilities exclude claims against third parties and are not discounted. The current portion of these accruals is included in “Accounts payable and accrued expenses” and the long-term portion is included in “Other noncurrent liabilities” in the consolidated balance sheets. In general, legal fees related to environmental remediation and litigation are charged to expense. The Company includes the interest component of any litigation-related penalties within “Interest expense” in the consolidated statements of operations.
Income Taxes
Income taxes are accounted for using a balance sheet approach. The Company accounts for deferred income taxes by applying statutory tax rates in effect at the reporting date of the balance sheet to differences between the book and tax basis of assets and liabilities. A valuation allowance is established if it is “more likely than not” that the related tax benefits will not be realized. Significant weight is given to evidence that can be objectively verified including history of tax attribute expiration and cumulative income or loss. In determining the appropriate valuation allowance, the Company considers the projected realization of tax benefits based on expected levels of future taxable income, available tax planning strategies, reversals of existing taxable temporary differences and taxable income in carryback years.
The Company recognizes the tax benefit from uncertain tax positions only if it is “more likely than not” the tax position will be sustained on examination by the taxing authorities based on the technical merits of the position. The tax benefits recognized from such a position are measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement.settlement. To the extent the Company’s assessment of such tax positions changes, the change in estimate will be recorded in the period in which the determination is made. Tax-related interest and penalties are classified as a component of income tax expense.
| Peabody Energy Corporation | 2022 Form 10-K | F-14 | ||||||
Postretirement Health Care and Life Insurance Benefits
The Company accounts for postretirement benefits other than pensions by accruing the costs of benefits to be provided over the employees’ period of active service. These costs are determined on an actuarial basis. The Company’s consolidated balance sheets reflect the accumulated postretirement benefit obligations of its postretirement benefit plans. The Company accounts for changes in its postretirement benefit obligations as a settlement when an irrevocable action has been effected that relieves the Company of its actuarially-determined liability to individual plan participants and removes substantial risk surrounding the nature, amount and timing of the obligation’s funding and the assets used to effect the settlement. The Company records amounts attributable to actuarial valuation changes currently in earnings rather than recording such amounts within accumulated other comprehensive income and amortizing to expense over applicable time periods. See Note 17.13. “Postretirement Health Care and Life Insurance Benefits” for information related to postretirement benefits.
Pension Plans
The Company sponsors non-contributory defined benefit pension plans accounted for by accruing the cost to provide the benefits over the employees’ period of active service. These costs are determined on an actuarial basis. The Company’s consolidated balance sheets reflect the funded status of the defined benefit pension plans. The Company records amounts attributable to actuarial valuation changes currently in earnings rather than recording such amounts within accumulated other comprehensive income and amortizing to expense over applicable time periods. See Note 18.14. “Pension and Savings Plans” for information related to pension plans.
Restructuring Activities
From time to time, the Company initiates restructuring activities in connection with its repositioning efforts to appropriately align its cost structure or optimize its coal production relative to prevailing market conditions. Costs associated with restructuring actions can include the impact of early mine closures, voluntary and involuntary workforce reductions, office closures and other related activities. Costs associated with restructuring activities are recognized in the period incurred.
Included as a component of “Restructuring charges” in the Company’s consolidated statements of operations for the years ended December 31, 20192022, 2021 and 2018 and the period April 2 through December 31, 20172020 were aggregate restructuring charges of $24.3$2.9 million, $1.2$8.3 million and $7.6$37.9 million, respectively, primarily associated with voluntary and involuntary workforce reductions. There were 0 restructuring charges during the period January 1 through April 1, 2017. As of December 31, 2019,2022, a $7.4$0.8 million accrual for restructuring charges remained in “Accounts payable and accrued expenses,” which is expected to be paid in the first quarter of 2020.2023.
Derivatives
The Company recognizes at fair value all contracts meeting the definition of a derivative as assets or liabilities in the consolidated balance sheets, with the exception of certain coal tradingsales contracts for which the Company has elected to apply a normal purchases and normal sales exception.
With respect to derivatives used in hedging activities, the Company assesses at hedge inception whether such derivatives are highly effective at offsetting the changes in the anticipated exposure of the hedged item. The change in the fair value of derivatives designated as a cash flow hedge is recorded in “Accumulated other comprehensive income” in the consolidated balance sheets until the hedged transaction impacts reported earnings, at which time any gain or loss is reclassified to earnings. If the hedge ceases to qualify for hedge accounting, the Company prospectively recognizes changes in the fair value of the instrument in earnings in the period of the change. Gains or losses from derivative financial instruments designated as fair value hedges are recognized immediately in earnings, along with the offsetting gain or loss related to the underlying hedged item.
The Company’s asset and liability derivative positions are offset on a counterparty-by-counterparty basis if the contractual agreement provides for the net settlement of contracts with the counterparty in the event of default or termination of any one contract.
Non-derivative contracts and derivative contracts for which the Company has elected to apply the normal purchases and normal sales exception are accounted for on an accrual basis.
| Peabody Energy Corporation | 2022 Form 10-K | F-15 | ||||||
Business Combinations
The Company accounts for business combinations using the purchase method of accounting. The purchase method requires the Company to determine the fair value of all acquired assets, including identifiable intangible assets and all assumed liabilities. The total cost of acquisitions is allocated to the underlying identifiable net assets, based on their respective estimated fair values. Determining the fair value of assets acquired and liabilities assumed requires management’s judgment and the utilization of independent valuation experts, and often involves the use of significant estimates and assumptions, including assumptions with respect to future cash inflows and outflows, discount rates and asset lives, among other items.
Impairment of Long-Lived Assets
The Company evaluates its long-lived assets held and used in operations for impairment as events and changes in circumstances indicate that the carrying amount of such assets might not be recoverable. Factors that would indicate potential impairment to be present include, but are not limited to, a sustained history of operating or cash flow losses, an unfavorable change in earnings and cash flow outlook, prolonged adverse industry or economic trends and a significant adverse change in the extent or manner in which a long-lived asset is being used or in its physical condition. The Company generally does not view short-term declines in thermal and metallurgical coal prices as a triggering event for conducting impairment tests because of historic price volatility. However, the Company generally does view a sustained trend of depressed coal pricing (for example, over periods exceeding one year) as an indicator of potential impairment. Because of the volatile and cyclical nature of coal prices and demand, it is reasonably possible that coal prices may decrease and/or fail to improve in the near term, which, absent sufficient mitigation such as an offsetting reduction in the Company’s operating costs, may result in the need for future adjustments to the carrying value of the Company’s long-lived mining assets and mining-related investments.
Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. For its active mining operations, the Company generally groups such assets at the mine level, or the mining complex level for mines that share infrastructure, with the exception of impairment evaluations triggered by mine closures. In those cases involving mine closures, the related assets are evaluated at the individual asset level for remaining economic life based on transferability to ongoing operating sites or for expected salvage. For its development and exploration properties and portfolio of surface land and coal reserve and resource holdings, the Company considers several factors to determine whether to evaluate those assets individually or on a grouped basis for purposes of impairment testing. Such factors include geographic proximity to one another, the expectation of shared infrastructure upon development based on future mining plans and whether it would be most advantageous to bundle such assets in the event of sale to a third party.
When indicators of impairment are present, the Company evaluates its long-lived assets for recoverability by comparing the estimated undiscounted cash flows expected to be generated by those assets under various assumptions to their carrying amounts. If such undiscounted cash flows indicate that the carrying value of the asset group is not recoverable, impairment losses are measured by comparing the estimated fair value of the asset group to its carrying amount. As quoted market prices are unavailable for the Company’s individual mining operations, fair value is determined through the use of an expected present value technique based on the income approach, except for non-strategic coal reserves, resources, surface lands and undeveloped coal properties excluded from the Company’s long-range mine planning. In those cases, a market approach is utilized based on the most comparable market multiples available. The estimated future cash flows and underlying assumptions used to assess recoverability and, if necessary, measure the fair value of the Company’s long-lived mining assets are derived from those developed in connection with the Company’s planning and budgeting process. The Company believes its assumptions to be consistent with those a market participant would use for valuation purposes. The most critical assumptions underlying the Company’s projections and fair value estimates include those surrounding future tons sold, coal prices for unpriced coal, production costs (including costs for labor, commodity supplies and contractors), transportation costs, foreign currency exchange rates and a risk-adjusted, cost of capital (all of which generally constitute unobservable Level 3 inputs under the fair value hierarchy), in addition to market multiples for non-strategic coal reserves, resources, surface lands and undeveloped coal properties excluded from the Company’s long-range mine planning (which generally constitute Level 2 inputs under the fair value hierarchy).
Refer to Note 5.3. “Asset Impairment” for details regarding impairment charges related to long-lived assets of $261.2$9.5 million and $30.5$1,487.4 million recognized during the yearyears ended December 31, 20192022 and the period January 1 through April 1, 2017, respectively.2020. There were 0no impairment charges related to long-lived assets during the year ended December 31, 2018 or the period April 2 through December 31, 2017.2021.
| Peabody Energy Corporation | 2022 Form 10-K | F-16 | ||||||
Fair Value
For assets and liabilities that are recognized or disclosed at fair value in the consolidated financial statements, the Company defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.
Foreign Currency
Functional currency is determined by the primary economic environment in which an entity operates, which for the Company’s foreign operations is generally the U.S. dollar because sales prices in international coal markets and the Company’s sources of financing those operations are denominated in that currency. Accordingly, substantially all of the Company’s consolidated foreign subsidiaries utilize the U.S. dollar as their functional currency. Monetary assets and liabilities are remeasured at year-end exchange rates while non-monetary items are remeasured at historical rates. Income and expense accounts are remeasured at the average rates in effect during the year, except for those expenses related to balance sheet amounts that are remeasured at historical exchange rates. Gains and losses from foreign currency remeasurement related to tax balances are included as a component of “Income tax (benefit) provision, (benefit),” while all other remeasurement gains and losses are included in “Operating costs and expenses” in the consolidated statements of operations. The total impact of foreign currency remeasurement on the consolidated statements of operations was a net lossgain of $2.7 million, $3.1 million, and $4.0 million for the yearyears ended December 31, 20192022, 2021 and a net gain of $1.4 million, $0.7 million and $10.6 million for the year ended December 31, 2018 and the periods April 2 through December 31, 2017 and January 1 through April 1, 2017,2020, respectively.
The Company owns a 50% equity interest in Middlemount Coal Pty Ltd. (Middlemount), which owns the Middlemount Mine in Queensland, Australia. Middlemount utilizes the Australian dollar as its functional currency. Accordingly, the assets and liabilities of that equity investee are translated to U.S. dollars at the year-end exchange rate and income and expense accounts are translated at the average rate in effect during the year. The Company’s pro-rata share of the translation gains and losses of the equity investee are recorded as a component of “Accumulated other comprehensive income” in the consolidated balance sheets. Australian dollar denominated stockholder loans to the Middlemount Mine, which are long term in nature, are considered part of the Company’s net investment in that operation. Accordingly, foreign currency gains or losses on those loans are recorded as a component of foreign currency translation adjustment. The Company recorded foreign currency translation gainslosses of $0.2 million, $1.4$1.6 million and $5.5$1.0 million for the years ended December 31, 2022 and 2021, respectively, and a net gain of $6.1 million for the year ended December 31, 2019 and the periods April 2 through December 31, 2017 and January 1 through April 1, 2017, respectively, and a loss of $5.9 million for the year ended December 31, 2018.2020.
Share-Based Compensation
The Company accounts for share-based compensation at the grant date fair value of awards and recognizes the related expense over the service period of the awards. See Note 20.16. “Share-Based Compensation” for information related to share-based compensation.
Exploration and Drilling Costs
Exploration expenditures are charged to operating costs as incurred, including costs related to drilling and study costs incurred to convert or upgrade mineral resources to reserves.
Advance Stripping Costs
Pre-production. At existing surface operations, additional pits may be added to increase production capacity in order to meet customer requirements. These expansions may require significant capital to purchase additional equipment, expand the workforce, build or improve existing haul roads and create the initial pre-production box cut to remove overburden (that is, advance stripping costs) for new pits at existing operations. If these pits operate in a separate and distinct area of the mine, the costs associated with initially uncovering coal (that is, advance stripping costs incurred for the initial box cuts) for production are capitalized and amortized over the life of the developed pit consistent with coal industry practices.
Post-production. Advance stripping costs related to post-production are expensed as incurred. Where new pits are routinely developed as part of a contiguous mining sequence, the Company expenses such costs as incurred. The development of a contiguous pit typically reflects the planned progression of an existing pit, thus maintaining production levels from the same mining area utilizing the same employee group and equipment.
| Peabody Energy Corporation | 2022 Form 10-K | F-17 | ||||||
Use of Estimates in the Preparation of the Consolidated Financial Statements
These consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the U.S. (U.S. GAAP).GAAP. In doing so, estimates and assumptions are made that affect the amounts reported in the consolidated financial statements and accompanying notes. These estimates are based on historical experience and on various other assumptions deemed reasonable under the circumstances, the results of which form the basis for making judgments about the carrying amounts of assets and liabilities that are not readily apparent from other sources. The Company’s actual results may differ materially from these estimates. Significant estimates inherent in the preparation of these consolidated financial statements include, but are not limited to, accounting for sales and cost recognition, postretirement benefit plans, environmental receivables and liabilities, asset retirement obligations, evaluation of long-lived assets for impairment, income taxes including deferred tax assets, fair value measurements and contingencies.
| Successor | Predecessor | |||||||
| Year Ended December 31, 2018 | January 1 through April 1, 2017 | |||||||
| (Dollars in millions) | ||||||||
| Gain on settlement of claims | $ | (12.8 | ) | $ | (3,031.2 | ) | ||
| Fresh start adjustments, net | — | 3,363.1 | ||||||
| Fresh start income tax adjustments, net | — | 253.9 | ||||||
| Professional fees | — | 42.5 | ||||||
| Accounts payable settlement gains | — | (0.7 | ) | |||||
| Interest income | — | (0.4 | ) | |||||
| Reorganization items, net | $ | (12.8 | ) | $ | 627.2 | |||
| (Dollars in millions) | |||
| Liabilities subject to compromise | $ | 8,416.7 | |
| Less amounts issued to settle claims: | |||
| Successor Common Stock (at par) | (0.7 | ) | |
| Successor Series A Convertible Preferred Stock | (1,305.4 | ) | |
| Successor Additional paid-in capital | (1,774.9 | ) | |
| Issuance of Successor Notes | (1,000.0 | ) | |
| Issuance of Successor Term Loan | (950.0 | ) | |
| Cash payments and accruals for claims and professional fees | (336.4 | ) | |
| Other: | |||
| Write-off of Predecessor debt issuance costs | (18.1 | ) | |
| Gain on settlement of claims | $ | 3,031.2 | |
| (Dollars in millions) | ||||
| Inventories | (a) | $ | 70.1 | |
| Other current assets | (b) | (333.0 | ) | |
| Property, plant, equipment and mine development, net | (c) | (3,461.4 | ) | |
| Investments and other assets | (d) | 238.0 | ||
| Accounts payable and accrued expenses | (e) | (14.8 | ) | |
| Deferred income taxes | (f) | 177.8 | ||
| Asset retirement obligations | (g) | 73.9 | ||
| Accrued postretirement benefit costs | (h) | 6.9 | ||
| Other noncurrent liabilities | (i) | (120.6 | ) | |
| Total fresh start adjustments, net | $ | (3,363.1 | ) | |
| Preliminary Allocations | Adjustments | Final Allocations | |||||||||
| (Dollars in millions) | |||||||||||
| Inventories | $ | 39.7 | $ | 0.2 | $ | 39.9 | |||||
| Property, plant, equipment and mine development | 364.7 | 0.6 | 365.3 | ||||||||
| Current liabilities | (4.1 | ) | — | (4.1 | ) | ||||||
| Asset retirement obligations | (10.5 | ) | (0.8 | ) | (11.3 | ) | |||||
| Total purchase price | $ | 389.8 | $ | — | $ | 389.8 | |||||
| Successor | |||||||
| Year Ended December 31, 2018 | April 2 through December 31, 2017 | ||||||
| (Dollars in millions, except per share data) | |||||||
| Revenues | $ | 6,008.4 | $ | 4,506.2 | |||
| Income from continuing operations, net of income taxes | 826.6 | 783.3 | |||||
| Basic earnings per share from continuing operations | $ | 5.84 | $ | 4.37 | |||
| Diluted earnings per share from continuing operations | $ | 5.75 | $ | 4.33 | |||
(2) Revenue Recognition |
Disaggregation of RevenuesRevenue
Revenue by product type and market is set forth in the following tables. With respect to its seaborne miningreporting segments, the Company classifies as “Export” certain revenue from domestically-delivered coal under contracts in which the price is derived on a basis similar to export contracts.
| Year Ended December 31, 2022 | |||||||||||||||||||||||||||||||||||
| Seaborne Thermal Mining | Seaborne Metallurgical Mining | Powder River Basin Mining | Other U.S. Thermal Mining | Corporate and Other (1) | Consolidated | ||||||||||||||||||||||||||||||
| (Dollars in millions) | |||||||||||||||||||||||||||||||||||
| Thermal coal | |||||||||||||||||||||||||||||||||||
| Domestic | $ | 167.6 | $ | — | $ | 1,066.0 | $ | 943.9 | $ | — | $ | 2,177.5 | |||||||||||||||||||||||
| Export | 1,177.3 | — | — | 3.5 | — | 1,180.8 | |||||||||||||||||||||||||||||
| Total thermal | 1,344.9 | — | 1,066.0 | 947.4 | — | 3,358.3 | |||||||||||||||||||||||||||||
| Metallurgical coal | |||||||||||||||||||||||||||||||||||
| Export | — | 1,610.8 | — | — | — | 1,610.8 | |||||||||||||||||||||||||||||
| Total metallurgical | — | 1,610.8 | — | — | — | 1,610.8 | |||||||||||||||||||||||||||||
Other (2) | 0.7 | 6.1 | (0.5) | 4.8 | 1.7 | 12.8 | |||||||||||||||||||||||||||||
| Revenue | $ | 1,345.6 | $ | 1,616.9 | $ | 1,065.5 | $ | 952.2 | $ | 1.7 | $ | 4,981.9 | |||||||||||||||||||||||
| Successor | |||||||||||||||||||||||||||
| Year Ended December 31, 2019 | |||||||||||||||||||||||||||
| Seaborne Thermal Mining | Seaborne Metallurgical Mining | Powder River Basin Mining | Midwestern U.S. Mining | Western U.S. Mining | Corporate and Other (1) | Consolidated | |||||||||||||||||||||
| (Dollars in millions) | |||||||||||||||||||||||||||
| Thermal coal | |||||||||||||||||||||||||||
| Domestic | $ | 147.9 | $ | — | $ | 1,208.9 | $ | 669.2 | $ | 605.0 | $ | — | $ | 2,631.0 | |||||||||||||
| Export | 822.4 | — | — | — | 11.3 | — | 833.7 | ||||||||||||||||||||
| Total thermal | 970.3 | — | 1,208.9 | 669.2 | 616.3 | — | 3,464.7 | ||||||||||||||||||||
| Metallurgical coal | |||||||||||||||||||||||||||
| Export | — | 1,030.0 | — | — | — | — | 1,030.0 | ||||||||||||||||||||
| Total metallurgical | — | 1,030.0 | — | — | — | — | 1,030.0 | ||||||||||||||||||||
| Other | 1.4 | 3.1 | 19.8 | 0.5 | 23.4 | 80.5 | 128.7 | ||||||||||||||||||||
| Revenues | $ | 971.7 | $ | 1,033.1 | $ | 1,228.7 | $ | 669.7 | $ | 639.7 | $ | 80.5 | $ | 4,623.4 | |||||||||||||
| Year Ended December 31, 2021 | |||||||||||||||||||||||||||||||||||
| Seaborne Thermal Mining | Seaborne Metallurgical Mining | Powder River Basin Mining | Other U.S. Thermal Mining | Corporate and Other (1) | Consolidated | ||||||||||||||||||||||||||||||
| (Dollars in millions) | |||||||||||||||||||||||||||||||||||
| Thermal coal | |||||||||||||||||||||||||||||||||||
| Domestic | $ | 173.5 | $ | — | $ | 970.7 | $ | 669.9 | $ | — | $ | 1,814.1 | |||||||||||||||||||||||
| Export | 759.0 | — | — | 10.0 | — | 769.0 | |||||||||||||||||||||||||||||
| Total thermal | 932.5 | — | 970.7 | 679.9 | — | 2,583.1 | |||||||||||||||||||||||||||||
| Metallurgical coal | |||||||||||||||||||||||||||||||||||
| Export | — | 719.8 | — | — | — | 719.8 | |||||||||||||||||||||||||||||
| Total metallurgical | — | 719.8 | — | — | — | 719.8 | |||||||||||||||||||||||||||||
Other (2) | 1.5 | 7.9 | 0.5 | 9.2 | (3.7) | 15.4 | |||||||||||||||||||||||||||||
| Revenue | $ | 934.0 | $ | 727.7 | $ | 971.2 | $ | 689.1 | $ | (3.7) | $ | 3,318.3 | |||||||||||||||||||||||
| Peabody Energy Corporation | ||||||||
| Year Ended December 31, 2020 | |||||||||||||||||||||||||||||||||||
| Seaborne Thermal Mining | Seaborne Metallurgical Mining | Powder River Basin Mining | Other U.S. Thermal Mining | Corporate and Other (1) | Consolidated | ||||||||||||||||||||||||||||||
| (Dollars in millions) | |||||||||||||||||||||||||||||||||||
| Thermal coal | |||||||||||||||||||||||||||||||||||
| Domestic | $ | 145.5 | $ | — | $ | 993.9 | $ | 675.2 | $ | — | $ | 1,814.6 | |||||||||||||||||||||||
| Export | 564.8 | — | — | — | — | 564.8 | |||||||||||||||||||||||||||||
| Total thermal | 710.3 | — | 993.9 | 675.2 | — | 2,379.4 | |||||||||||||||||||||||||||||
| Metallurgical coal | |||||||||||||||||||||||||||||||||||
| Export | — | 484.3 | — | — | — | 484.3 | |||||||||||||||||||||||||||||
| Total metallurgical | — | 484.3 | — | — | — | 484.3 | |||||||||||||||||||||||||||||
Other (2) | 1.5 | 2.2 | (2.8) | 32.1 | (15.6) | 17.4 | |||||||||||||||||||||||||||||
| Revenue | $ | 711.8 | $ | 486.5 | $ | 991.1 | $ | 707.3 | $ | (15.6) | $ | 2,881.1 | |||||||||||||||||||||||
| Successor | |||||||||||||||||||||||||||
| Year Ended December 31, 2018 | |||||||||||||||||||||||||||
| Seaborne Thermal Mining | Seaborne Metallurgical Mining | Powder River Basin Mining | Midwestern U.S. Mining | Western U.S. Mining | Corporate and Other (1) | Consolidated | |||||||||||||||||||||
| (Dollars in millions) | |||||||||||||||||||||||||||
| Thermal coal | |||||||||||||||||||||||||||
| Domestic | $ | 153.0 | $ | — | $ | 1,424.8 | $ | 799.4 | $ | 543.1 | $ | — | $ | 2,920.3 | |||||||||||||
| Export | 945.0 | — | — | 1.3 | 22.1 | — | 968.4 | ||||||||||||||||||||
| Total thermal | 1,098.0 | — | 1,424.8 | 800.7 | 565.2 | — | 3,888.7 | ||||||||||||||||||||
| Metallurgical coal | |||||||||||||||||||||||||||
| Export | — | 1,548.6 | — | — | — | — | 1,548.6 | ||||||||||||||||||||
| Total metallurgical | — | 1,548.6 | — | — | — | — | 1,548.6 | ||||||||||||||||||||
| Other | 1.2 | 4.4 | — | 0.3 | 26.8 | 111.8 | 144.5 | ||||||||||||||||||||
| Revenues | $ | 1,099.2 | $ | 1,553.0 | $ | 1,424.8 | $ | 801.0 | $ | 592.0 | $ | 111.8 | $ | 5,581.8 | |||||||||||||
| Successor | |||||||||||||||||||||||||||
| April 2 through December 31, 2017 | |||||||||||||||||||||||||||
| Seaborne Thermal Mining | Seaborne Metallurgical Mining | Powder River Basin Mining | Midwestern U.S. Mining | Western U.S. Mining | Corporate and Other (1) | Consolidated | |||||||||||||||||||||
| (Dollars in millions) | |||||||||||||||||||||||||||
| Thermal coal | |||||||||||||||||||||||||||
| Domestic | $ | 87.9 | $ | — | $ | 1,174.3 | $ | 586.7 | $ | 409.8 | $ | — | $ | 2,258.7 | |||||||||||||
| Export | 684.1 | — | — | 5.3 | 19.2 | — | 708.6 | ||||||||||||||||||||
| Total thermal | 772.0 | — | 1,174.3 | 592.0 | 429.0 | — | 2,967.3 | ||||||||||||||||||||
| Metallurgical coal | |||||||||||||||||||||||||||
| Export | — | 1,221.0 | — | — | — | — | 1,221.0 | ||||||||||||||||||||
| Total metallurgical | — | 1,221.0 | — | — | — | — | 1,221.0 | ||||||||||||||||||||
| Other | 0.5 | — | 4.4 | 0.3 | 11.7 | 47.4 | 64.3 | ||||||||||||||||||||
| Revenues | $ | 772.5 | $ | 1,221.0 | $ | 1,178.7 | $ | 592.3 | $ | 440.7 | $ | 47.4 | $ | 4,252.6 | |||||||||||||
| Predecessor | |||||||||||||||||||||||||||
| January 1 through April 1, 2017 | |||||||||||||||||||||||||||
| Seaborne Thermal Mining | Seaborne Metallurgical Mining | Powder River Basin Mining | Midwestern U.S. Mining | Western U.S. Mining | Corporate and Other (1) | Consolidated | |||||||||||||||||||||
| (Dollars in millions) | |||||||||||||||||||||||||||
| Thermal coal | |||||||||||||||||||||||||||
| Domestic | $ | 27.3 | $ | — | $ | 394.3 | $ | 193.2 | $ | 133.5 | $ | — | $ | 748.3 | |||||||||||||
| Export | 197.2 | — | — | — | — | — | 197.2 | ||||||||||||||||||||
| Total thermal | 224.5 | — | 394.3 | 193.2 | 133.5 | — | 945.5 | ||||||||||||||||||||
| Metallurgical coal | |||||||||||||||||||||||||||
| Export | — | 324.6 | — | — | — | — | 324.6 | ||||||||||||||||||||
| Total metallurgical | — | 324.6 | — | — | — | — | 324.6 | ||||||||||||||||||||
| Other | 0.3 | 4.3 | — | — | 16.2 | 35.3 | 56.1 | ||||||||||||||||||||
| Revenues | $ | 224.8 | $ | 328.9 | $ | 394.3 | $ | 193.2 | $ | 149.7 | $ | 35.3 | $ | 1,326.2 | |||||||||||||
| Year Ended December 31, | |||||||||||||||||
| 2022 | 2021 | 2020 | |||||||||||||||
| (Dollars in millions) | |||||||||||||||||
| Unrealized losses on derivative contracts related to forecasted sales | $ | (35.8) | $ | (115.1) | $ | (29.6) | |||||||||||
| Realized (losses) gains on derivative contracts related to forecasted sales | (455.1) | (45.6) | 34.3 | ||||||||||||||
Revenue from physical sale of coal (3) | 470.7 | 140.3 | (28.6) | ||||||||||||||
| Trading revenue | 10.7 | 6.1 | (0.7) | ||||||||||||||
Other (2) | 11.2 | 10.6 | 9.0 | ||||||||||||||
| Total Corporate and Other | $ | 1.7 | $ | (3.7) | $ | (15.6) | |||||||||||
(2) Includes revenue from arrangements such as customer contract-related payments associated with volume shortfalls, royalties related to coal lease agreements, sales agency commissions, farm income and property and facility rentals.
| Successor | |||||||||||||||||||||||||||
| Year Ended December 31, 2019 | |||||||||||||||||||||||||||
| Seaborne Thermal Mining | Seaborne Metallurgical Mining | Powder River Basin Mining | Midwestern U.S. Mining | Western U.S. Mining | Corporate and Other (1) | Consolidated | |||||||||||||||||||||
| (Dollars in millions) | |||||||||||||||||||||||||||
| One year or longer | $ | 589.2 | $ | 828.6 | $ | 1,087.6 | $ | 644.3 | $ | 609.9 | $ | — | $ | 3,759.6 | |||||||||||||
| Less than one year | 381.1 | 201.4 | 121.3 | 24.9 | 6.4 | — | 735.1 | ||||||||||||||||||||
Other (2) | 1.4 | 3.1 | 19.8 | 0.5 | 23.4 | 80.5 | 128.7 | ||||||||||||||||||||
| Revenues | $ | 971.7 | $ | 1,033.1 | $ | 1,228.7 | $ | 669.7 | $ | 639.7 | $ | 80.5 | $ | 4,623.4 | |||||||||||||
| Successor | |||||||||||||||||||||||||||
| Year Ended December 31, 2018 | |||||||||||||||||||||||||||
| Seaborne Thermal Mining | Seaborne Metallurgical Mining | Powder River Basin Mining | Midwestern U.S. Mining | Western U.S. Mining | Corporate and Other (1) | Consolidated | |||||||||||||||||||||
| (Dollars in millions) | |||||||||||||||||||||||||||
| One year or longer | $ | 799.5 | $ | 1,036.7 | $ | 1,283.9 | $ | 775.4 | $ | 531.8 | $ | — | $ | 4,427.3 | |||||||||||||
| Less than one year | 298.5 | 511.9 | 140.9 | 25.3 | 33.4 | — | 1,010.0 | ||||||||||||||||||||
Other (2) | 1.2 | 4.4 | — | 0.3 | 26.8 | 111.8 | 144.5 | ||||||||||||||||||||
| Revenues | $ | 1,099.2 | $ | 1,553.0 | $ | 1,424.8 | $ | 801.0 | $ | 592.0 | $ | 111.8 | $ | 5,581.8 | |||||||||||||
| Successor | |||||||||||||||||||||||||||
| April 2 through December 31, 2017 | |||||||||||||||||||||||||||
| Seaborne Thermal Mining | Seaborne Metallurgical Mining | Powder River Basin Mining | Midwestern U.S. Mining | Western U.S. Mining | Corporate and Other (1) | Consolidated | |||||||||||||||||||||
| (Dollars in millions) | |||||||||||||||||||||||||||
| One year or longer | $ | 503.0 | $ | 867.1 | $ | 1,023.1 | $ | 560.5 | $ | 404.6 | $ | — | $ | 3,358.3 | |||||||||||||
| Less than one year | 269.0 | 353.9 | 151.2 | 31.5 | 24.4 | — | 830.0 | ||||||||||||||||||||
Other (2) | 0.5 | — | 4.4 | 0.3 | 11.7 | 47.4 | 64.3 | ||||||||||||||||||||
| Revenues | $ | 772.5 | $ | 1,221.0 | $ | 1,178.7 | $ | 592.3 | $ | 440.7 | $ | 47.4 | $ | 4,252.6 | |||||||||||||
| Predecessor | |||||||||||||||||||||||||||
| January 1 through April 1, 2017 | |||||||||||||||||||||||||||
| Seaborne Thermal Mining | Seaborne Metallurgical Mining | Powder River Basin Mining | Midwestern U.S. Mining | Western U.S. Mining | Corporate and Other (1) | Consolidated | |||||||||||||||||||||
| (Dollars in millions) | |||||||||||||||||||||||||||
| One year or longer | $ | 134.1 | $ | 240.6 | $ | 357.7 | $ | 193.2 | $ | 129.3 | $ | — | $ | 1,054.9 | |||||||||||||
| Less than one year | 90.4 | 84.0 | 36.6 | — | 4.2 | — | 215.2 | ||||||||||||||||||||
Other (2) | 0.3 | 4.3 | — | — | 16.2 | 35.3 | 56.1 | ||||||||||||||||||||
| Revenues | $ | 224.8 | $ | 328.9 | $ | 394.3 | $ | 193.2 | $ | 149.7 | $ | 35.3 | $ | 1,326.2 | |||||||||||||
Committed Revenue from Contracts with Customers
The Company expects to recognize revenue subsequent to December 31, 20192022 of approximately $4.7$6.3 billion related to contracts with customers in which volumes and prices per ton were fixed or reasonably estimable at December 31, 2019.2022. Approximately 48%40% of such amount is expected to be recognized over the next twelve months and the remainder thereafter. Actual revenue related to such contracts may differ materially for various reasons, including price adjustment features for coal quality and cost escalations, volume optionality provisions and potential force majeure events. This estimate of future revenue does not include any revenue related to contracts with variable prices per ton that cannot be reasonably estimated, such as the majority of seaborne metallurgical and seaborne thermal coal contracts where pricing is negotiated or settled quarterly or annually.
Accounts Receivable
“Accounts receivable, net” at December 31, 20192022 and 20182021 consisted of the following:
| December 31, | |||||||
| 2019 | 2018 | ||||||
| (Dollars in millions) | |||||||
| Trade receivables, net | $ | 283.1 | $ | 345.5 | |||
| Miscellaneous receivables, net | 46.4 | 104.9 | |||||
| Accounts receivable, net | $ | 329.5 | $ | 450.4 | |||
| December 31, | |||||||||||
| 2022 | 2021 | ||||||||||
| (Dollars in millions) | |||||||||||
| Trade receivables, net | $ | 416.3 | $ | 307.0 | |||||||
| Miscellaneous receivables, net | 49.2 | 43.5 | |||||||||
| Accounts receivable, net | $ | 465.5 | $ | 350.5 | |||||||
| Peabody Energy Corporation | ||||||||
| Successor | Predecessor | |||||||||||||
| Year Ended December 31, 2019 | Year Ended December 31, 2018 | April 2 through December 31, 2017 | January 1 through April 1, 2017 | |||||||||||
| (Dollars in millions) | ||||||||||||||
| Income (loss) from discontinued operations, net of income taxes | $ | 3.2 | $ | 18.1 | $ | (19.8 | ) | $ | (16.2 | ) | ||||
| December 31, | |||||||
| 2019 | 2018 | ||||||
| (Dollars in millions) | |||||||
| Liabilities: | |||||||
| Accounts payable and accrued expenses | $ | 58.8 | $ | 54.0 | |||
| Other noncurrent liabilities | 105.5 | 141.1 | |||||
| Total liabilities classified as discontinued operations | $ | 164.3 | $ | 195.1 | |||
Inventories as of December 31, 20192022 and December 31, 20182021 consisted of the following:
| December 31, | |||||||
| 2019 | 2018 | ||||||
| (Dollars in millions) | |||||||
| Materials and supplies | $ | 116.3 | $ | 118.1 | |||
| Raw coal | 85.1 | 53.6 | |||||
| Saleable coal | 130.1 | 108.5 | |||||
| Inventories | $ | 331.5 | $ | 280.2 | |||
| December 31, | |||||||||||
| 2022 | 2021 | ||||||||||
| (Dollars in millions) | |||||||||||
| Materials and supplies, net | $ | 130.8 | $ | 102.1 | |||||||
| Raw coal | 98.3 | 54.6 | |||||||||
| Saleable coal | 67.0 | 70.0 | |||||||||
| Inventories, net | $ | 296.1 | $ | 226.7 | |||||||
Materials and supplies inventories presented above have been shown net of reserves of $7.9$9.5 million and $0.2$9.0 million as of December 31, 20192022 and 2018,2021, respectively.
(5) Equity Method Investments
The Company’s equity method investments include its joint venture interest in Middlemount and certain other equity method investments.
The table below summarizes the book value of those investments, and related financing receivables, which are reported in “Investments and other assets” in the consolidated balance sheets, and the related “Income“(Income) loss from equity affiliates”:
| Successor | Predecessor | |||||||||||||||||||||
| Book Value at | (Income) Loss from Equity Affiliates | |||||||||||||||||||||
| December 31, 2019 | December 31, 2018 | Year Ended December 31, 2019 | Year Ended December 31, 2018 | April 2 through December 31, 2017 | January 1 through April 1, 2017 | |||||||||||||||||
| (Dollars in millions) | ||||||||||||||||||||||
| Equity method investment and financing receivables related to Middlemount | $ | 56.3 | $ | 45.0 | $ | (9.0 | ) | $ | (69.3 | ) | $ | (48.6 | ) | $ | (17.4 | ) | ||||||
| Other equity method investments | 0.6 | 0.9 | 5.6 | 1.2 | (0.4 | ) | 2.4 | |||||||||||||||
| Total equity method investments and financing receivables related to Middlemount | $ | 56.9 | $ | 45.9 | $ | (3.4 | ) | $ | (68.1 | ) | $ | (49.0 | ) | $ | (15.0 | ) | ||||||
| Book Value at | (Income) Loss from Equity Affiliates | ||||||||||||||||||||||||||||
| December 31, | Year Ended December 31, | ||||||||||||||||||||||||||||
| 2022 | 2021 | 2022 | 2021 | 2020 | |||||||||||||||||||||||||
| (Dollars in millions) | |||||||||||||||||||||||||||||
| Equity method investment related to Middlemount | $ | 27.1 | $ | 62.2 | $ | (135.1) | $ | (82.1) | $ | 60.1 | |||||||||||||||||||
| Other equity method investments | 7.0 | — | 3.9 | — | — | ||||||||||||||||||||||||
| Total equity method investments | $ | 34.1 | $ | 62.2 | $ | (131.2) | $ | (82.1) | $ | 60.1 | |||||||||||||||||||
The Company received cash payments from Middlemount of $14.7 million, $106.7 million, $48.1$168.4 million and $32.7$43.5 million during the years ended December 31, 20192022 and 2018,2021, respectively. No payments were received from Middlemount during the period April 2 throughyear ended December 31, 2017 and the period January 1 through April 1, 2017, respectively.2020.
| Peabody Energy Corporation | 2022 Form 10-K | F-20 | ||||||
One of the Company’s Australian subsidiaries and the other shareholder of Middlemount are partiesis party to an agreement as amended from time to time, to provide a revolving loan (Revolving Loans) to Middlemount. The Company’s participation in the Revolving Loansrevolving loan will not, at any time, exceed its 50% equity interest of the revolving loan limit, which was $50 million Australian dollars and fully drawn upon by Middlemount at December 31, 2019. Subsequent to December 31, 2019, the parties amended the agreement to temporarily increase the2022. The revolving loan limit to $70 million Australian dollars through August 2020, at which time the revolving loan limit will revert to $50 million Australian dollars.
During the year ended December 31, 20182020, the Company determined thatestablished a valuation allowance on Middlemount’s net deferred tax position of approximately $33 million primarily based upon recent cumulative losses. During the year ended December 31, 2021, the Company determined that the valuation allowance was no longer necessary based on recent cumulative earnings and expectation of future earnings. The determination resulted in approximately $9$33 million of income which was more than offset by a tax reserverelated to the release of approximately $17 million due to an uncertain tax position relating to an ongoing income tax audit of Middlemount. the previously established valuation allowance.
During the year ended December 31, 2021, Middlemount entered into an insurance claim settlement agreement attributable to a business interruption and property damage claim from 2019, Middlemount received notification thatwhich resulted in $12.5 million of income for the Australian Taxation Office would no longer pursue its position, and the related tax reserve was released.Company (on a 50% basis).
During the years ended December 31, 20192022, 2021 and 2018, the period April 2 through December 31, 2017, and the period January 1 through April 1, 2017,2020, respectively, Middlemount generated revenuesrevenue of approximately $160$441 million, $271 million, $193$265 million and $60$123 million (on a 50% basis).
Middlemount had current assets, noncurrent assets, current liabilities and noncurrent liabilities of $30.8$75.2 million, $209.7$256.3 million, $225.8$135.7 million and $40.1$97.7 million, respectively, as of December 31, 20192022 and $33.6$83.1 million, $181.8$269.9 million, $187.9$254.9 million and $35.8$79.5 million, respectively, as of December 31, 20182021 (on a 50% basis).
(6) Derivatives and Fair Value Measurements |
Derivatives
From time to time, the Company may utilize various types of derivative instruments to manage its exposure to risks in the normal course of business, including (1) foreign currency exchange rate risk and the variability of cash flows associated with forecasted Australian dollar expenditures made in its Australian mining platform, (2) price risk of fluctuating coal prices related to forecasted sales or purchases of coal, or changes in the fair value of a fixed price physical sales contract, (3) price risk and the variability of cash flows related to forecasted diesel fuel purchased for use in its operations and (4) interest rate risk on long-term debt. These risk management activities are actively monitored for compliance with the Company’s risk management policies.
On a limited basis, the Company engages in the direct and brokered trading of coal and freight-related contracts. Except those contracts for which the Company has elected to apply a normal purchases and normal sales exception, all derivative coal trading contracts are accounted for at fair value. The Company had no diesel fuel or interest rate derivatives in place as of December 31, 2022.
Foreign Currency Option Contracts
The Company has historically utilized currency forwards and options to hedge currency risk associated with anticipated Australian dollar expenditures. As of December 31, 2019,2022, the Company had currency options outstanding with an aggregate notional amount of $925.0$745.0 million Australian dollars to hedge currency risk associated with anticipated Australian dollar expenditures over the first nine months of 2020.nine-month period ending September 30, 2023. The instruments are quarterly average rate options which entitle the Company to receive payment on the notional amount should the quarterly average Australian dollar-to-U.S. dollar exchange rate exceed amounts ranging from $0.73$0.70 to $0.75$0.77 over the first nine monthsnine-month period ending September 30, 2023. Subsequent to December 31, 2022, the Company entered into additional average rate options with an aggregate notional amount of 2020.$135.0 million Australian dollars related to the second and third quarters of 2023 and purchased collars with an aggregate notional amount of $150.0 million Australian dollars related to the second half of 2023. The additional average rate options have a strike price of $0.75. The purchased collars have a floor and ceiling of $0.63 and $0.75, respectively, whereby the Company would incur a loss on the instruments for rates below the floor and gain for rates above the ceiling.
Derivative Contracts Related to Forecasted Sales
As of December 31, 2019,2022, the Company held coal-related financialcoal derivative contracts related to a portion of its forecasted sales forwith an aggregate notional volume of 2.00.6 million tonnes. Such financial contracts may include futures, forwards and options. Of the aggregateThe notional volume 1.7 millionis related predominantly to financial derivatives entered to support the profitability of the Wambo Underground Mine as part of a strategy to extend the mine’s life. All such tonnes will settle in 2020 and2023. Additionally, the remainder will settle in 2021.Company classifies certain physical forward sales contracts as derivatives for which the normal purchase, normal sales exception does not apply.
| Peabody Energy Corporation | 2022 Form 10-K | F-21 | ||||||
During the year ended December 31, 2019.2022, the Company recorded a net unrealized mark-to-market loss of $35.8 million on these coal derivative contracts, which included approximately $65 million of unrealized mark-to-market losses on financial derivatives and approximately $29 million of unrealized mark-to-market gains on physical forward sales contracts. During the year ended December 31, 2021, the Company recorded a net unrealized mark-to-market loss of $115.1 million, which included approximately $86 million of unrealized mark-to-market losses on financial derivatives and approximately $29 million of unrealized mark-to-market losses on physical forward sales contracts. During the year ended December 31, 2020, the Company recorded a net unrealized mark-to-market loss of $29.6 million, which included approximately $28 million of unrealized mark-to-market losses on financial derivatives and approximately $1 million of unrealized mark-to-market losses on physical forward sales contracts.
On a limited basis, the Company engages in the direct and brokered trading ofmay enter coal and freight-related contracts (coal trading). Except thoseor freight derivative contracts for which thetrading purposes. Such financial contracts may include futures, forwards and options. The Company has elected to apply a normal purchases and normal sales exception, all derivative coalheld nominal financial trading contracts are accounted for at fair value. Coal brokering is conducted both as principal and agent in support of various coal production-related activities that may involve coal produced from the Company’s mines, coal sourcing arrangements with third-party mining companies or offtake agreements with other coal producers. The Company also provides transportation-related services, which involve both financial derivative contracts and physical contracts. Collectively, coal and freight-related hedging activities include both economic hedging and, from time to time, cash flow hedging in support of the Company’s coal trading strategy. Revenues from such transactions include realized and unrealized gains and losses on derivative instruments, including those that arise from coal deliveries related to contracts accounted for on an accrual basis under the normal purchases and normal sales exception.December 31, 2022.
The Company has master netting agreements with certain of its counterparties which allow for the settlement of contracts in an asset position with contracts in a liability position in the event of default or termination. Such netting arrangements reduce the Company’s credit exposure related to these counterparties. For classification purposes, the Company records the net fair value of all the positions with a given counterparty as a net asset or liability in the consolidated balance sheets.
The fair value of derivatives reflected in the accompanying consolidated balance sheets are set forth in the table below.
| December 31, 2022 | December 31, 2021 | ||||||||||||||||||||||
| Asset Derivative | Liability Derivative | Asset Derivative | Liability Derivative | ||||||||||||||||||||
| (Dollars in millions) | |||||||||||||||||||||||
| Foreign currency option contracts | $ | 3.0 | $ | — | $ | 1.4 | $ | — | |||||||||||||||
| Derivative contracts related to forecasted sales | 100.6 | (310.3) | 59.5 | (184.2) | |||||||||||||||||||
| Financial trading contracts | 11.7 | — | 3.4 | — | |||||||||||||||||||
| Total derivatives | 115.3 | (310.3) | 64.3 | (184.2) | |||||||||||||||||||
| Effect of counterparty netting | (100.6) | 100.6 | (59.5) | 59.5 | |||||||||||||||||||
| Variation margin (received) posted | (11.7) | 209.7 | (3.4) | 95.2 | |||||||||||||||||||
| Net derivatives and variation margin as classified in the balance sheets | $ | 3.0 | $ | — | $ | 1.4 | $ | (29.5) | |||||||||||||||
| December 31, 2019 | December 31, 2018 | ||||||||||||||
| Asset Derivative | Liability Derivative | Asset Derivative | Liability Derivative | ||||||||||||
| (Dollars in millions) | |||||||||||||||
| Foreign currency option contracts | $ | 1.1 | $ | — | $ | 1.2 | $ | — | |||||||
| Coal contracts related to forecasted sales | 20.1 | (0.1 | ) | 6.6 | (23.1 | ) | |||||||||
| Coal trading contracts | 81.1 | (74.2 | ) | 59.7 | (64.4 | ) | |||||||||
| Total derivatives | 102.3 | (74.3 | ) | 67.5 | (87.5 | ) | |||||||||
| Effect of counterparty netting | (74.3 | ) | 74.3 | (64.5 | ) | 64.5 | |||||||||
| Variation margin (held) posted | (22.1 | ) | — | — | 21.8 | ||||||||||
| Net derivatives and margin as classified in the balance sheets | $ | 5.9 | $ | — | $ | 3.0 | $ | (1.2 | ) | ||||||
The net amount of asset derivatives, net of variation margin, areis included in “Other current assets” and the net amount of liability derivatives, net of variation margin, areis included in “Accounts payable and accrued expenses” in the accompanying consolidated balance sheets. The amounts of initial margin are not included with the derivatives presented in the tabular disclosures above and are included in “Other current assets” in the accompanying consolidated balance sheets.
| Peabody Energy Corporation | 2022 Form 10-K | F-22 | ||||||
PEABODY ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Currently, the Company does not seek cash flow hedge accounting treatment for its currency- or coal-related derivative financial instruments and thus changes in fair value are reflected in current earnings.
The tables below show the amounts of pre-taxpretax gains and losses related to the Company’s derivatives.
| Successor | ||||||||||||
| Year Ended December 31, 2019 | ||||||||||||
| Total (loss) gain recognized in income | (Loss) gain realized in income on derivatives | Unrealized gain recognized in income on derivatives | ||||||||||
| Financial Instrument | ||||||||||||
| (Dollars in millions) | ||||||||||||
| Foreign currency option contracts | $ | (3.7 | ) | $ | (4.9 | ) | $ | 1.2 | ||||
| Coal contracts related to forecasted sales | 67.6 | 25.4 | 42.2 | |||||||||
| Coal trading contracts | (0.3 | ) | (8.7 | ) | 8.4 | |||||||
| Total | $ | 63.6 | $ | 11.8 | $ | 51.8 | ||||||
| Successor | ||||||||||||
| Year Ended December 31, 2018 | ||||||||||||
| Total (loss) gain recognized in income | (Loss) gain realized in income on derivatives | Unrealized (loss) gain recognized in income on derivatives | ||||||||||
| Financial Instrument | ||||||||||||
| (Dollars in millions) | ||||||||||||
| Foreign currency option contracts | $ | (9.1 | ) | $ | (8.4 | ) | $ | (0.7 | ) | |||
| Coal contracts related to forecasted sales | 115.7 | 97.4 | 18.3 | |||||||||
| Coal trading contracts | (2.9 | ) | (5.3 | ) | 2.4 | |||||||
| Total | $ | 103.7 | $ | 83.7 | $ | 20.0 | ||||||
| Successor | ||||||||||||
| April 2 through December 31, 2017 | ||||||||||||
| Total gain (loss) recognized in income | Gain (loss) realized in income on derivatives | Unrealized (loss) gain recognized in income on derivatives | ||||||||||
| Financial Instrument | ||||||||||||
| (Dollars in millions) | ||||||||||||
| Foreign currency option contracts | $ | 1.8 | $ | 3.3 | $ | (1.5 | ) | |||||
| Coal contracts related to forecasted sales | 12.1 | 35.1 | (23.0 | ) | ||||||||
| Coal trading contracts | (1.6 | ) | (8.3 | ) | 6.7 | |||||||
| Total | $ | 12.3 | $ | 30.1 | $ | (17.8 | ) | |||||
| Predecessor | ||||||||||||||||
| January 1 through April 1, 2017 | ||||||||||||||||
| Total (loss) gain recognized in income | Gain (loss) realized in income on derivatives | Unrealized gain recognized in income on derivatives | Loss reclassified from other comprehensive loss into income | |||||||||||||
| Financial Instrument | ||||||||||||||||
| (Dollars in millions) | ||||||||||||||||
| Commodity swap contracts | $ | (11.0 | ) | $ | — | $ | — | $ | (11.0 | ) | ||||||
| Foreign currency forward contracts | (16.6 | ) | — | — | (16.6 | ) | ||||||||||
| Financial coal contracts - Company production | 29.2 | 12.7 | 16.5 | — | ||||||||||||
| Coal trading contracts | 2.2 | (11.3 | ) | 13.5 | — | |||||||||||
| Total | $ | 3.8 | $ | 1.4 | $ | 30.0 | $ | (27.6 | ) | |||||||
| Year Ended December 31, 2022 | ||||||||||||||||||||||||||
| Total (loss) gain recognized in income | (Loss) gain realized in income on derivatives | Unrealized (loss) gain recognized in income on derivatives | ||||||||||||||||||||||||
| Derivative Instrument | Classification | |||||||||||||||||||||||||
| (Dollars in millions) | ||||||||||||||||||||||||||
| Foreign currency option contracts | Operating costs and expenses | $ | (8.4) | $ | (6.1) | $ | (2.3) | |||||||||||||||||||
| Derivative contracts related to forecasted sales | Revenue | (490.9) | (455.1) | (35.8) | ||||||||||||||||||||||
| Financial trading contracts | Revenue | 10.7 | 1.1 | 9.6 | ||||||||||||||||||||||
| Total | $ | (488.6) | $ | (460.1) | $ | (28.5) | ||||||||||||||||||||
| Year Ended December 31, 2021 | ||||||||||||||||||||||||||
| Total (loss) gain recognized in income | Gain (loss) realized in income on derivatives | Unrealized (loss) gain recognized in income on derivatives | ||||||||||||||||||||||||
| Derivative Instrument | Classification | |||||||||||||||||||||||||
| (Dollars in millions) | ||||||||||||||||||||||||||
| Foreign currency option contracts | Operating costs and expenses | $ | (5.7) | $ | 1.8 | $ | (7.5) | |||||||||||||||||||
| Derivative contracts related to forecasted sales | Revenue | (160.7) | (45.6) | (115.1) | ||||||||||||||||||||||
| Financial trading contracts | Revenue | 6.1 | 4.6 | 1.5 | ||||||||||||||||||||||
| Total | $ | (160.3) | $ | (39.2) | $ | (121.1) | ||||||||||||||||||||
| Year Ended December 31, 2020 | ||||||||||||||||||||||||||
| Total gain (loss) recognized in income | Gain realized in income on derivatives | Unrealized gain (loss) recognized in income on derivatives | ||||||||||||||||||||||||
| Derivative Instrument | Classification | |||||||||||||||||||||||||
| (Dollars in millions) | ||||||||||||||||||||||||||
| Foreign currency option contracts | Operating costs and expenses | $ | 12.9 | $ | 5.8 | $ | 7.1 | |||||||||||||||||||
| Derivative contracts related to forecasted sales | Revenue | 4.7 | 34.3 | (29.6) | ||||||||||||||||||||||
| Financial trading contracts | Revenue | (0.7) | 4.2 | (4.9) | ||||||||||||||||||||||
| Total | $ | 16.9 | $ | 44.3 | $ | (27.4) | ||||||||||||||||||||
The Company classifies the cash effects of its derivatives within the “Cash Flows From Operating Activities” section of the consolidated statements of cash flows.
Fair Value Measurements
The Company uses a three-level fair value hierarchy that categorizes assets and liabilities measured at fair value based on the observability of the inputs utilized in the valuation. These levels include: Level 1 - inputs are quoted prices in active markets for the identical assets or liabilities; Level 2 - inputs are other than quoted prices included in Level 1 that are directly or indirectly observable through market-corroborated inputs; and Level 3 - inputs are unobservable, or observable but cannot be market-corroborated, requiring the Company to make assumptions about pricing by market participants.
| Peabody Energy Corporation | 2022 Form 10-K | F-23 | ||||||
The following tables set forth the hierarchy of the Company’s net financial asset (liability) positions for which fair value is measured on a recurring basis:basis. Variation margin cash associated with the derivative balances is excluded from this table.
| December 31, 2019 | |||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | ||||||||||||
| (Dollars in millions) | |||||||||||||||
| Foreign currency option contracts | $ | — | $ | 1.1 | $ | — | $ | 1.1 | |||||||
| Coal contracts related to forecasted sales | — | 21.2 | — | 21.2 | |||||||||||
| Coal trading contracts | — | (16.4 | ) | — | (16.4 | ) | |||||||||
| Equity securities | — | — | 4.0 | 4.0 | |||||||||||
| Total net financial assets | $ | — | $ | 5.9 | $ | 4.0 | $ | 9.9 | |||||||
| December 31, 2018 | |||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | ||||||||||||
| (Dollars in millions) | |||||||||||||||
| Foreign currency option contracts | $ | — | $ | 1.2 | $ | — | $ | 1.2 | |||||||
| Coal contracts related to forecasted sales | — | (21.2 | ) | — | (21.2 | ) | |||||||||
| Coal trading contracts | — | 21.8 | — | 21.8 | |||||||||||
| Equity securities | — | — | 10.0 | 10.0 | |||||||||||
| Total net financial assets | $ | — | $ | 1.8 | $ | 10.0 | $ | 11.8 | |||||||
| December 31, 2022 | |||||||||||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||
| (Dollars in millions) | |||||||||||||||||||||||
| Foreign currency option contracts | $ | — | $ | 3.0 | $ | — | $ | 3.0 | |||||||||||||||
| Derivative contracts related to forecasted sales | — | (209.7) | — | (209.7) | |||||||||||||||||||
| Financial trading contracts | — | 11.7 | — | 11.7 | |||||||||||||||||||
| Equity securities | — | — | 2.5 | 2.5 | |||||||||||||||||||
| Total net (liabilities) assets | $ | — | $ | (195.0) | $ | 2.5 | $ | (192.5) | |||||||||||||||
| December 31, 2021 | |||||||||||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||
| (Dollars in millions) | |||||||||||||||||||||||
| Foreign currency option contracts | $ | — | $ | 1.4 | $ | — | $ | 1.4 | |||||||||||||||
| Derivative contracts related to forecasted sales | — | (124.7) | — | (124.7) | |||||||||||||||||||
| Financial trading contracts | — | 3.4 | — | 3.4 | |||||||||||||||||||
| Equity securities | — | — | 4.0 | 4.0 | |||||||||||||||||||
| Total net (liabilities) assets | $ | — | $ | (119.9) | $ | 4.0 | $ | (115.9) | |||||||||||||||
For Level 1 and 2 financial assets and liabilities, the Company utilizes both direct and indirect observable price quotes, including interest rate yield curves, exchange indices, broker/dealer quotes, published indices, issuer spreads, benchmark securities and other market quotes. In the case of certain debt securities, fair value is provided by a third-party pricing service. Below is a summary of the Company’s valuation techniques for Level 1 and 2 financial assets and liabilities:
•Foreign currency option contracts:contracts are valued utilizing inputs obtained in quoted public markets (Level 2) except when credit and non-performance risk is considered to be a significant input, then the Company classifies such contracts as Level 3.
•Investments in equity securities are based on observed prices in an inactive market (Level 3).
Other Financial Instruments. The following methods and assumptions were used by the Company in estimating fair values for other financial instruments as of December 31, 20192022 and 2018:2021:
•Cash and cash equivalents, restricted cash, accounts receivable, including those within the Company’s accounts receivable securitization program, margining cash, notes receivable and accounts payable have carrying values which approximate fair value due to the short maturity or the liquid nature of these instruments.
•Long-term debt fair value estimates are based on observed prices for securities with an active trading market when available (Level 2), and otherwise on estimated borrowing rates to discount the cash flows to their present value (Level 3).
| Peabody Energy Corporation | ||||||||
Market risk associated with the Company’s fixed- and variable-rate long-term debt relates to the potential reduction in the fair value and negative impact to future earnings, respectively, from an increase in interest rates. The fair value of debt, shown below, is principally based on reported market values recently completed market transactions and estimates based on interest rates, maturities, credit risk, underlying collateral and underlying collateral.completed market transactions.
| December 31, | |||||||
| 2019 | 2018 | ||||||
| (Dollars in millions) | |||||||
| Total debt at par value | $ | 1,367.2 | $ | 1,437.0 | |||
| Less: Unamortized debt issuance costs and original issue discount | (56.4 | ) | (70.0 | ) | |||
| Net carrying amount | $ | 1,310.8 | $ | 1,367.0 | |||
| Estimated fair value | $ | 1,271.1 | $ | 1,366.2 | |||
| December 31, | |||||||||||
| 2022 | 2021 | ||||||||||
| (Dollars in millions) | |||||||||||
| Total debt at par value | $ | 343.6 | $ | 1,173.2 | |||||||
| Less: Unamortized debt issuance costs and original issue discount | (9.8) | (35.4) | |||||||||
| Net carrying amount | $ | 333.8 | $ | 1,137.8 | |||||||
| Estimated fair value | $ | 560.0 | $ | 1,136.5 | |||||||
The Company’s risk management function, which is independent of the Company’s coal trading function, is responsible for valuation policies and procedures, with oversight from executive management. The fair value of the Company’s coal derivative assets and liabilities reflects adjustments for credit risk. The Company’s exposure is substantially with electric utilities, energy marketers, steel producers and nonfinancial trading houses.
Generally, the Company’s Level 3 instruments or contracts are valued using bid/ask price quotations and other market assessments obtained from multiple, independent third-party brokers or other transactional data incorporated into internally-generated discounted cash flow models. Decreases in the number of third-party brokers or market liquidity could erode the quality of market information and therefore the valuation of the Company’s market positions. The Company’s valuation techniques include basis adjustments to the foregoing price inputs for quality, such as sulfur and ash content, location differentials, expressed as port and freight costs, and credit risk. The Company’s risk management function independently validates the Company’s valuation inputs, including unobservable inputs, with third-party information and settlement prices from other sources where available. A daily process is performed to analyze market price changes and changes to the portfolio. Further periodic validation occurs at the time contracts are settled with the counterparty. These valuation techniques have been consistently applied in all periods presented, and the Company believes it has obtained the most accurate information available for the types of derivative contracts held.
Significant increases or decreases in the inputs in isolation could result in a significantly higher or lower fair value measurement. The unobservable inputs do not have a direct interrelationship; therefore, a change in one unobservable input would not necessarily correspond with a change in another unobservable input.
The following table summarizes the changes in the Company’s recurring Level 3 net financial assets (liabilities):assets:
| Successor | Predecessor | |||||||||||||
| Year Ended December 31, 2019 | Year Ended December 31, 2018 | April 2 through December 31, 2017 | January 1 through April 1, 2017 | |||||||||||
| (Dollars in millions) | ||||||||||||||
| Beginning of period | $ | 10.0 | $ | — | $ | (0.7 | ) | $ | (1.1 | ) | ||||
| Transfers into Level 3 | — | — | — | — | ||||||||||
| Transfers out of Level 3 | — | — | 0.7 | 0.2 | ||||||||||
| Total (losses) gains realized/unrealized: | ||||||||||||||
| Included in earnings | (9.0 | ) | (1.7 | ) | — | 0.2 | ||||||||
| Purchases | 3.0 | 10.0 | — | — | ||||||||||
| Sales | — | — | — | — | ||||||||||
| Settlements | — | 1.7 | — | — | ||||||||||
| End of period | $ | 4.0 | $ | 10.0 | $ | — | $ | (0.7 | ) | |||||
| Year Ended December 31, | ||||||||||||||||||||
| 2022 | 2021 | 2020 | ||||||||||||||||||
| (Dollars in millions) | ||||||||||||||||||||
| Beginning of period | $ | 4.0 | $ | 4.0 | $ | 4.0 | ||||||||||||||
| Impairment loss included in earnings | (1.7) | — | — | |||||||||||||||||
| Purchases | 0.2 | — | — | |||||||||||||||||
| End of period | $ | 2.5 | $ | 4.0 | $ | 4.0 | ||||||||||||||
The Company had no transfers between Levels 1, 2 and 23 during any of the periods presented in the table above. Transfers of liabilities into/out of Level 3 from/to Level 2 during the periods presented were due to the relative value of unobservable inputs to the total fair value measurement of certain derivative contracts falling below, or in the case of transfers in, rising above, the 10% threshold. The Company’s policy is to value all transfers between levels using the beginning of period valuation.
| Peabody Energy Corporation | ||||||||
| Successor | Predecessor | |||||||||||||
| Year Ended December 31, 2019 | Year Ended December 31, 2018 | April 2 through December 31, 2017 | January 1 through April 1, 2017 | |||||||||||
| (Dollars in millions) | ||||||||||||||
Changes in unrealized gains (1) | $ | — | $ | — | $ | — | $ | 0.3 | ||||||
| December 31, 2019 | |||||||||||
| Assets | Liabilities | Net Total | |||||||||
| (Dollars in millions) | |||||||||||
| Coal supply agreements | $ | 20.7 | $ | (21.4 | ) | $ | (0.7 | ) | |||
| Take-or-pay contracts | — | (40.0 | ) | (40.0 | ) | ||||||
| Total | $ | 20.7 | $ | (61.4 | ) | $ | (40.7 | ) | |||
| Balance sheet classification: | |||||||||||
| Investments and other assets | $ | 20.7 | $ | — | $ | 20.7 | |||||
| Accounts payable and accrued expenses | — | (8.4 | ) | (8.4 | ) | ||||||
| Other noncurrent liabilities | — | (53.0 | ) | (53.0 | ) | ||||||
| Total | $ | 20.7 | $ | (61.4 | ) | $ | (40.7 | ) | |||
| December 31, 2018 | |||||||||||
| Assets | Liabilities | Net Total | |||||||||
| (Dollars in millions) | |||||||||||
| Coal supply agreements | $ | 70.9 | $ | (32.9 | ) | $ | 38.0 | ||||
| Take-or-pay contracts | — | (57.1 | ) | (57.1 | ) | ||||||
| Total | $ | 70.9 | $ | (90.0 | ) | $ | (19.1 | ) | |||
| Balance sheet classification: | |||||||||||
| Investments and other assets | $ | 70.9 | $ | — | $ | 70.9 | |||||
| Accounts payable and accrued expenses | — | (20.3 | ) | (20.3 | ) | ||||||
| Other noncurrent liabilities | — | (69.7 | ) | (69.7 | ) | ||||||
| Total | $ | 70.9 | $ | (90.0 | ) | $ | (19.1 | ) | |||
Property, plant, equipment and mine development, net, as of December 31, 20192022 and December 31, 20182021 consisted of the following:
| December 31, | |||||||
| 2019 | 2018 | ||||||
| (Dollars in millions) | |||||||
| Land and coal interests | $ | 4,022.4 | $ | 4,148.8 | |||
| Buildings and improvements | 547.9 | 559.3 | |||||
| Machinery and equipment | 1,518.6 | 1,456.3 | |||||
| Less: Accumulated depreciation, depletion and amortization | (1,409.8 | ) | (957.4 | ) | |||
| Property, plant, equipment and mine development, net | $ | 4,679.1 | $ | 5,207.0 | |||
| December 31, | |||||||||||
| 2022 | 2021 | ||||||||||
| (Dollars in millions) | |||||||||||
| Land and coal interests | $ | 2,514.7 | $ | 2,494.1 | |||||||
| Buildings and improvements | 594.2 | 550.8 | |||||||||
| Machinery and equipment | 1,543.1 | 1,386.2 | |||||||||
| Less: Accumulated depreciation, depletion and amortization | (1,787.0) | (1,480.5) | |||||||||
| Property, plant, equipment and mine development, net | $ | 2,865.0 | $ | 2,950.6 | |||||||
Land and coal interests included coal reserves and resources with a net book value of $2.8$1.3 billion as of December 31, 20192022 and $3.0$1.4 billion as of December 31, 2018.2021. Such coal reserves and resources were comprised of mineral rights for leased coal interests and advance royalties that had a net book value of $2.0 billion and $2.1$0.7 billion as of both December 31, 20192022 and 2018, respectively,2021, and coal reserves and resources held by fee ownership of $0.8$0.6 billion and $0.9 billion atas of both December 31, 20192022 and 2018,2021, respectively. The amount of coal reserves and resources unassigned to active mining operations, and thus not subject to current depletion, atincluding certain exploratory properties, where the Company was not currently engaged in mining operations or leasing to third parties was $0.1 billion and $0.2 billion as of December 31, 2019 and 2018, respectively.
Income (loss) from continuing operations before income taxes for the periods presented below consisted of the following:
| Successor | Predecessor | |||||||||||||
| Year Ended December 31, 2019 | Year Ended December 31, 2018 | April 2 through December 31, 2017 | January 1 through April 1, 2017 | |||||||||||
| (Dollars in millions) | ||||||||||||||
| U.S. | $ | (374.2 | ) | $ | (43.4 | ) | $ | 10.4 | $ | 2,408.7 | ||||
| Non-U.S. | 231.9 | 707.5 | 541.7 | (2,868.0 | ) | |||||||||
| Total | $ | (142.3 | ) | $ | 664.1 | $ | 552.1 | $ | (459.3 | ) | ||||
| Year Ended December 31, | |||||||||||||||||
| 2022 | 2021 | 2020 | |||||||||||||||
| (Dollars in millions) | |||||||||||||||||
| U.S. | $ | 59.7 | $ | (55.0) | $ | (1,771.5) | |||||||||||
| Non-U.S. | 1,218.9 | 425.2 | (80.3) | ||||||||||||||
| Total | $ | 1,278.6 | $ | 370.2 | $ | (1,851.8) | |||||||||||
| Year Ended December 31, | |||||||||||||||||
| 2022 | 2021 | 2020 | |||||||||||||||
| (Dollars in millions) | |||||||||||||||||
| Current: | |||||||||||||||||
| U.S. federal | $ | (0.2) | $ | (0.5) | $ | (23.9) | |||||||||||
| Non-U.S. | 42.9 | 30.8 | 2.4 | ||||||||||||||
| State | 0.1 | — | 1.7 | ||||||||||||||
| Total current | 42.8 | 30.3 | (19.8) | ||||||||||||||
| Deferred: | |||||||||||||||||
| U.S. federal | — | — | 23.4 | ||||||||||||||
| Non-U.S. | (81.6) | (7.5) | 4.4 | ||||||||||||||
| Total deferred | (81.6) | (7.5) | 27.8 | ||||||||||||||
| Total income tax (benefit) provision | $ | (38.8) | $ | 22.8 | $ | 8.0 | |||||||||||
| Peabody Energy Corporation | ||||||||
| Successor | Predecessor | |||||||||||||
| Year Ended December 31, 2019 | Year Ended December 31, 2018 | April 2 through December 31, 2017 | January 1 through April 1, 2017 | |||||||||||
| (Dollars in millions) | ||||||||||||||
| Current: | ||||||||||||||
| U.S. federal | $ | (21.5 | ) | $ | (46.8 | ) | $ | (101.4 | ) | $ | (3.1 | ) | ||
| Non-U.S. | 28.4 | 29.8 | 40.4 | 8.3 | ||||||||||
| State | (0.3 | ) | (0.1 | ) | (0.4 | ) | (6.7 | ) | ||||||
| Total current | 6.6 | (17.1 | ) | (61.4 | ) | (1.5 | ) | |||||||
| Deferred: | ||||||||||||||
| U.S. federal | 20.3 | 30.4 | (85.1 | ) | (101.0 | ) | ||||||||
| Non-U.S. | 19.3 | 5.7 | (14.5 | ) | (160.4 | ) | ||||||||
| State | (0.2 | ) | (0.6 | ) | — | (0.9 | ) | |||||||
| Total deferred | 39.4 | 35.5 | (99.6 | ) | (262.3 | ) | ||||||||
| Total income tax provision (benefit) | $ | 46.0 | $ | 18.4 | $ | (161.0 | ) | $ | (263.8 | ) | ||||
The following is a reconciliation of the expected statutory federal income tax expense (benefit) expense to the Company’s income tax (benefit) provision (benefit) for the periods presented below:
| Successor | Predecessor | |||||||||||||
| Year Ended December 31, 2019 | Year Ended December 31, 2018 | April 2 through December 31, 2017 | January 1 through April 1, 2017 | |||||||||||
| (Dollars in millions) | ||||||||||||||
| Expected income tax (benefit) expense at U.S. federal statutory rate | $ | (29.9 | ) | $ | 139.5 | $ | 193.2 | $ | (160.8 | ) | ||||
| Changes in valuation allowance, income tax | (32.0 | ) | (284.6 | ) | (744.9 | ) | (777.2 | ) | ||||||
| Remeasurement due to the Tax Cuts and Jobs Act | — | 9.5 | 473.5 | — | ||||||||||
| Reorganization costs | — | — | — | 2,130.0 | ||||||||||
| Bad debt deduction | — | — | — | (1,639.6 | ) | |||||||||
| Changes in tax reserves | 3.0 | 2.1 | 7.2 | (9.2 | ) | |||||||||
| Excess depletion | (19.3 | ) | (28.5 | ) | (40.4 | ) | (11.2 | ) | ||||||
| Foreign earnings repatriation | 76.1 | — | — | — | ||||||||||
| Foreign earnings provision differential | 45.6 | 97.1 | (26.3 | ) | 158.2 | |||||||||
| Global intangible low-taxed income | 6.1 | 68.2 | — | — | ||||||||||
| Remeasurement of foreign income tax accounts | (0.1 | ) | (0.2 | ) | (0.3 | ) | 9.4 | |||||||
| State income taxes, net of federal tax benefit | (13.2 | ) | 3.2 | (3.1 | ) | 40.6 | ||||||||
| Other, net | 9.7 | 12.1 | (19.9 | ) | (4.0 | ) | ||||||||
| Total income tax provision (benefit) | $ | 46.0 | $ | 18.4 | $ | (161.0 | ) | $ | (263.8 | ) | ||||
| Year Ended December 31, | |||||||||||||||||
| 2022 | 2021 | 2020 | |||||||||||||||
| (Dollars in millions) | |||||||||||||||||
| Expected income tax expense (benefit) at U.S. federal statutory rate | $ | 268.5 | $ | 77.7 | $ | (388.9) | |||||||||||
| Changes in valuation allowance, income tax | (595.6) | (101.3) | 410.1 | ||||||||||||||
| Changes in tax reserves | (1.5) | 1.9 | (7.7) | ||||||||||||||
| Excess depletion | (17.2) | (13.7) | (14.5) | ||||||||||||||
| Foreign earnings repatriation | 42.3 | — | — | ||||||||||||||
| Foreign earnings provision differential | 80.7 | 17.3 | 16.4 | ||||||||||||||
| Global intangible low-taxed income | 197.2 | 67.0 | — | ||||||||||||||
| Tax credits | — | (26.5) | — | ||||||||||||||
| Remeasurement of foreign income tax accounts | (2.6) | (1.8) | 2.9 | ||||||||||||||
| State income taxes, net of federal tax benefit | 1.1 | (1.1) | (6.8) | ||||||||||||||
| Other, net | (11.7) | 3.3 | (3.5) | ||||||||||||||
| Total income tax (benefit) provision | $ | (38.8) | $ | 22.8 | $ | 8.0 | |||||||||||
Certain reconciliation items included in the above table exclude the remeasurement of foreign income tax accounts as these foreign currency effects are separately presented.
On March 27, 2020, the Coronavirus Aid, Relief and Economic Security Act was signed into law and contained numerous tax provisions including the acceleration of refunds of previously generated alternative minimum tax (AMT) credits. During the years ended December 31, 2021 and 2020, the Company received AMT credit refunds of $1.2 million and $46.9 million, respectively. The Company does not expect any further AMT refund.
The Taxpayer Certainty and Disaster Relief Act of 2020 and the American Rescue Plan Act were enacted on December 27, 2020 and March 1, 2021, respectively. On August 16, 2022, the Inflation Reduction Act of 2022 was signed into law and contained numerous tax provisions including a 15% minimum tax on book income of certain large corporations and a 1% excise tax on net stock repurchases. These acts did not have a material impact on the Company’s tax provision.
| Peabody Energy Corporation | 2022 Form 10-K | F-27 | ||||||
The tax effects of temporary differences that gave rise to significant portions of the deferred tax assets and liabilities as of December 31, 20192022 and 20182021 consisted of the following:
| December 31, | |||||||
| 2019 | 2018 | ||||||
| (Dollars in millions) | |||||||
| Deferred tax assets: | |||||||
| Tax loss carryforwards and credits | $ | 1,530.9 | $ | 1,729.3 | |||
| Property, plant, equipment and mine development, principally due to differences in depreciation, depletion and asset impairments | 276.6 | 304.5 | |||||
| Accrued postretirement benefit obligations | 142.6 | 139.5 | |||||
| Asset retirement obligations | 86.6 | 47.2 | |||||
| Employee benefits | 25.3 | 24.8 | |||||
| Take or pay obligations | 12.0 | 17.1 | |||||
| Investments and other assets | 89.0 | 82.7 | |||||
| Workers’ compensation obligations | 7.6 | 6.2 | |||||
| Operating lease right-of-use assets | 20.8 | — | |||||
| Other | 16.7 | 38.2 | |||||
| Total gross deferred tax assets | 2,208.1 | 2,389.5 | |||||
| Valuation allowance, income tax | (2,068.4 | ) | (2,094.3 | ) | |||
| Total deferred tax assets | 139.7 | 295.2 | |||||
| Deferred tax liabilities: | |||||||
| Property, plant, equipment and mine development, principally due to differences in depreciation, depletion and asset impairments | 100.9 | 203.4 | |||||
| Operating lease liabilities | 20.8 | — | |||||
| Coal supply agreements | 3.1 | 9.3 | |||||
| Investments and other assets | 15.4 | 43.7 | |||||
| Total deferred tax liabilities | 140.2 | 256.4 | |||||
| Net deferred tax (liability) asset | $ | (0.5 | ) | $ | 38.8 | ||
| Deferred taxes are classified as follows: | |||||||
| Noncurrent deferred income tax asset | $ | 28.3 | $ | 48.5 | |||
| Noncurrent deferred income tax liability | (28.8 | ) | (9.7 | ) | |||
| Net deferred tax (liability) asset | $ | (0.5 | ) | $ | 38.8 | ||
| December 31, | |||||||||||
| 2022 | 2021 | ||||||||||
| (Dollars in millions) | |||||||||||
| Deferred tax assets: | |||||||||||
| Tax loss carryforwards and credits | $ | 740.1 | $ | 1,267.6 | |||||||
| Property, plant, equipment and mine development, principally due to differences in depreciation, depletion and asset impairments | 550.8 | 571.9 | |||||||||
| Accrued postretirement benefit obligations | 41.4 | 48.9 | |||||||||
| Asset retirement obligations | 95.1 | 91.4 | |||||||||
| Employee benefits | 22.1 | 19.9 | |||||||||
| Take-or-pay obligations | 8.2 | 9.5 | |||||||||
| Hedge activities | 49.1 | 36.8 | |||||||||
| Interest limitation | — | 7.9 | |||||||||
| Investments and other assets | 37.0 | 81.8 | |||||||||
| Workers’ compensation obligations | 7.1 | 7.2 | |||||||||
| Operating lease liabilities | 7.8 | 11.3 | |||||||||
| Other | 28.3 | 22.7 | |||||||||
| Total gross deferred tax assets | 1,587.0 | 2,176.9 | |||||||||
| Valuation allowance, income tax | (1,451.0) | (2,120.8) | |||||||||
| Total deferred tax assets | 136.0 | 56.1 | |||||||||
| Deferred tax liabilities: | |||||||||||
| Property, plant, equipment and mine development, principally due to differences in depreciation, depletion and asset impairments | 67.5 | 66.4 | |||||||||
| Operating lease right-of-use assets | 7.6 | 9.4 | |||||||||
| Investments and other assets | 6.6 | 7.6 | |||||||||
| Total deferred tax liabilities | 81.7 | 83.4 | |||||||||
| Net deferred tax asset (liability) | $ | 54.3 | $ | (27.3) | |||||||
| Deferred taxes are classified as follows: | |||||||||||
| Noncurrent deferred income tax asset | $ | 74.7 | $ | — | |||||||
| Noncurrent deferred income tax liability | (20.4) | (27.3) | |||||||||
| Net deferred tax asset (liability) | $ | 54.3 | $ | (27.3) | |||||||
As of December 31, 2019,2022, the Company had gross Australia NOLs of $3.2 billion$53.0 million in Australian dollars and gross U.S. federal NOLs of $2.5$1.7 billion. The Company’s tax loss carryforwards and credits of $1.5 billion$740.1 million as of December 31, 20192022 were comprised primarily of net Australia NOLs and capital tax loss carryforwards of $766.4$153.4 million, net federal NOLs of $530.6$345.3 million, state NOLs of $81.5 million, AMT credits of $23.4$82.3 million, tax general business credits (GBCs) of $112.6$139.1 million and other foreign NOLs of $14.5$18.4 million. The AMT credits will be fully refunded by 2022. The foreign tax loss carryforwards have no expiration date. The federal NOLs begin to expire in 2036. The state NOLs begin to expire in 2023 and the GBCs begin to expire in 2027.
| Peabody Energy Corporation | 2022 Form 10-K | F-28 | ||||||
In assessing the near-term use of NOLs and tax credits and corresponding valuation allowance adjustments, the Company evaluated the expected level of future taxable income, available tax planning strategies, reversals of existing taxable temporary differences and taxable income in carryback years. For the year ended December 31, 2019,2022, the Company continued to recordreleased the valuation allowances of $2.1 billion$74.7 million recorded against the Australia NOLs and net deferred tax asset positions, comprisedposition due to the significant current year utilization of NOLs and expected future realization of the deferred tax assets. The Company maintained valuation allowances of $1.5 billion against the U.S net deferred tax asset position of $976.8 million and against certain foreign deferred tax assets, primarily in Australia, of $0.9 billion in the U.S. and $1.2 billion in Australia.$474.2 million. Recognition of thosethe U.S. valuation allowances was driven by recent cumulative book losses, as determined by considering all sources of available income (including items classified as discontinued operations or recorded directly to “Accumulated other comprehensive income”), which limited the Company’s ability to look to future taxable income in assessing the realizability of the related assets. The valuation allowance against certain foreign deferred tax assets continues to be recorded due to unlikely realization.
Unrecognized Tax Benefits
Net unrecognized tax benefits (excluding interest and penalties) were recorded as follows in the consolidated balance sheets as of December 31, 20192022 and 2018:2021:
| December 31, | |||||||
| 2019 | 2018 | ||||||
| (Dollars in millions) | |||||||
| Deferred income taxes | $ | 15.5 | $ | 13.0 | |||
| Other noncurrent liabilities | 1.0 | 1.0 | |||||
| Net unrecognized tax benefits | $ | 16.5 | $ | 14.0 | |||
| Gross unrecognized tax benefits | $ | 16.5 | $ | 14.0 | |||
| December 31, | |||||||||||
| 2022 | 2021 | ||||||||||
| (Dollars in millions) | |||||||||||
| Deferred income taxes | $ | 8.2 | $ | 9.7 | |||||||
| Other noncurrent liabilities | 1.3 | 1.3 | |||||||||
| Net unrecognized tax benefits | $ | 9.5 | $ | 11.0 | |||||||
| Gross unrecognized tax benefits | $ | 9.5 | $ | 11.0 | |||||||
The amount of the Company’s gross unrecognized tax benefits increaseddecreased by $2.5$1.5 million since December 31, 20182021 due primarily to adjustments to existingfor prior year positions andpartially offset by additions for current positions. The amount of the net unrecognized tax benefits that, if recognized, would directly affect the effective tax rate was $16.5$9.5 million and $14.0$11.0 million at December 31, 20192022 and 2018,2021, respectively. A reconciliation of the beginning and ending amount of gross unrecognized tax benefits for the periods presented below is as follows:
| Successor | Predecessor | |||||||||||||
| Year Ended December 31, 2019 | Year Ended December 31, 2018 | April 2 through December 31, 2017 | January 1 through April 1, 2017 | |||||||||||
| (Dollars in millions) | ||||||||||||||
| Balance at beginning of period | $ | 14.0 | $ | 12.7 | $ | 12.5 | $ | 20.1 | ||||||
| Additions for current year tax positions | 2.2 | 1.8 | 0.8 | — | ||||||||||
| Additions (reductions) for prior year tax positions | 0.3 | — | (0.5 | ) | (7.6 | ) | ||||||||
| Reductions for settlements with tax authorities | — | (0.5 | ) | (0.1 | ) | — | ||||||||
| Balance at end of period | $ | 16.5 | $ | 14.0 | $ | 12.7 | $ | 12.5 | ||||||
| Year Ended December 31, | |||||||||||||||||
| 2022 | 2021 | 2020 | |||||||||||||||
| (Dollars in millions) | |||||||||||||||||
| Balance at beginning of period | $ | 11.0 | $ | 9.1 | $ | 16.5 | |||||||||||
| Additions for current year tax positions | 0.8 | 3.0 | 1.9 | ||||||||||||||
| Reductions for prior year tax positions | (2.3) | (1.1) | (9.3) | ||||||||||||||
| Balance at end of period | $ | 9.5 | $ | 11.0 | $ | 9.1 | |||||||||||
The Company recognizes interest and penalties related to unrecognized tax benefits in its income tax provision. The Company recorded $0.4 million, $0.4 million and $4.8$0.2 million of gross interest and penalties for both the years ended December 31, 20192022 and 2018 and the period April 2 through December 31, 2017, respectively,2021, and reversed gross interest and penalties of $2.1$0.4 million for the period January 1 through April 1, 2017.year ended December 31, 2020. The Company had $5.8$5.9 million, $5.7 million and $5.4 million of accrued gross interest and penalties related to unrecognized tax benefits at December 31, 20192022, 2021 and 2018,2020, respectively.
The Company expectsdoes not expect a decrease of $5.3 million in its net unrecognized tax benefits during the next twelve months.
Tax Returns Subject to Examination
The Company’s federal income tax returns for the 2016 through 20182019, 2020 and 2021 tax years are subject to potential examinations by the Internal Revenue Service. The Company’s state income tax returns for the tax years 20002014 and thereafter remain potentially subject to examination by various state taxing authorities due to NOL carryforwards. Australian income tax returns for tax years 2013 through 20182020 continue to be subject to potential examinations by the Australian Taxation Office.
| Peabody Energy Corporation | 2022 Form 10-K | F-29 | ||||||
Foreign Earnings
As of December 31, 2019,2022, the Company has a consolidatedunremitted earnings relating to certain wholly owned subsidiaries that are not permanently reinvested, but there are no residual cash taxes on the unremitted earnings. The Company has an earnings deficit for remaining investments outside the U.S. but with some immaterial unremitted earnings in certain jurisdictions. The Companyand continues to be permanently reinvested with respect to its historical earnings. However, when appropriate, the Company has the ability to access foreign cash without incurring residual cash taxes due to the existence of NOLs.
Tax Payments and Refunds
The following table summarizes the Company’s income tax payments (refunds) payments,, net for the periods presented below:
| Successor | Predecessor | |||||||||||||
| Year Ended December 31, 2019 | Year Ended December 31, 2018 | April 2 through December 31, 2017 | January 1 through April 1, 2017 | |||||||||||
| (Dollars in millions) | ||||||||||||||
| U.S. — federal | $ | (45.7 | ) | $ | (103.1 | ) | $ | (11.2 | ) | $ | — | |||
| U.S. — state and local | 0.3 | (1.6 | ) | — | — | |||||||||
| Non-U.S. | 36.3 | 40.7 | 10.4 | 5.5 | ||||||||||
| Total income tax (refunds) payments, net | $ | (9.1 | ) | $ | (64.0 | ) | $ | (0.8 | ) | $ | 5.5 | |||
| Year Ended December 31, | |||||||||||||||||
| 2022 | 2021 | 2020 | |||||||||||||||
| (Dollars in millions) | |||||||||||||||||
| U.S. — federal | $ | (0.3) | $ | (1.3) | $ | (44.6) | |||||||||||
| U.S. — state and local | — | — | 1.6 | ||||||||||||||
| Non-U.S. | 36.9 | 12.9 | 3.1 | ||||||||||||||
| Total income tax payments (refunds), net | $ | 36.6 | $ | 11.6 | $ | (39.9) | |||||||||||
(9) Accounts Payable and Accrued Expenses |
Accounts payable and accrued expenses consisted of the following:
| December 31, | |||||||
| 2019 | 2018 | ||||||
| (Dollars in millions) | |||||||
| Trade accounts payable | $ | 254.8 | $ | 281.7 | |||
| Accrued payroll and related benefits | 186.2 | 209.3 | |||||
| Other accrued expenses | 118.5 | 184.9 | |||||
| Accrued taxes other than income | 99.0 | 111.4 | |||||
| Asset retirement obligations | 98.2 | 63.8 | |||||
| Accrued royalties | 61.7 | 52.7 | |||||
| Liabilities associated with discontinued operations | 58.8 | 54.0 | |||||
| Operating lease liabilities | 29.6 | — | |||||
| Accrued health care insurance | 15.8 | 10.0 | |||||
| Accrued interest | 15.0 | 15.7 | |||||
| Workers’ compensation obligations | 8.4 | 7.0 | |||||
| Intangible take-or-pay contracts | 8.4 | 20.3 | |||||
| Income taxes payable | 2.6 | 10.0 | |||||
| Liabilities from coal trading activities | — | 1.2 | |||||
| Accounts payable and accrued expenses | $ | 957.0 | $ | 1,022.0 | |||
| December 31, | |||||||||||
| 2022 | 2021 | ||||||||||
| (Dollars in millions) | |||||||||||
| Trade accounts payable | $ | 240.7 | $ | 201.7 | |||||||
| Accrued payroll and related benefits | 199.4 | 170.5 | |||||||||
| Other accrued expenses | 148.0 | 161.3 | |||||||||
| Accrued royalties | 88.4 | 51.4 | |||||||||
| Asset retirement obligations | 84.2 | 65.0 | |||||||||
| Liabilities associated with discontinued operations | 41.9 | 45.0 | |||||||||
| Income taxes payable | 25.9 | 20.2 | |||||||||
| Accrued insurance | 22.7 | 17.8 | |||||||||
| Accrued taxes other than income | 20.0 | 78.8 | |||||||||
| Operating lease liabilities | 16.8 | 16.4 | |||||||||
| Workers’ compensation obligations | 9.3 | 8.5 | |||||||||
| Accrued interest | 8.2 | 6.0 | |||||||||
| Liabilities from coal trading activities | — | 29.5 | |||||||||
| Accounts payable and accrued expenses | $ | 905.5 | $ | 872.1 | |||||||
| Peabody Energy Corporation | ||||||||
| December 31, | |||||||
| 2019 | 2018 | ||||||
| (Dollars in millions) | |||||||
| 6.000% Senior Secured Notes due March 2022 | $ | 459.0 | $ | 500.0 | |||
| 6.375% Senior Secured Notes due March 2025 | 500.0 | 500.0 | |||||
| Senior Secured Term Loan due 2025, net of original issue discount | 392.1 | 395.9 | |||||
| Finance lease obligations | 15.2 | 40.0 | |||||
| Less: Debt issuance costs | (55.5 | ) | (68.9 | ) | |||
| 1,310.8 | 1,367.0 | ||||||
| Less: Current portion of long-term debt | 18.3 | 36.5 | |||||
| Long-term debt | $ | 1,292.5 | $ | 1,330.5 | |||
| December 31, | |||||||||||
| Debt Instrument (defined below, as applicable) | 2022 | 2021 | |||||||||
| (Dollars in millions) | |||||||||||
| 6.000% Senior Secured Notes due March 2022 (2022 Notes) | $ | — | $ | 23.1 | |||||||
| 8.500% Senior Secured Notes due December 2024 (2024 Peabody Notes) | — | 62.6 | |||||||||
| 10.000% Senior Secured Notes due December 2024 (2024 Co-Issuer Notes) | — | 193.9 | |||||||||
| Senior Secured Term Loan due 2024 (Co-Issuer Term Loans) | — | 206.0 | |||||||||
| 6.375% Senior Secured Notes due March 2025 (2025 Notes) | — | 334.9 | |||||||||
| Senior Secured Term Loan due 2025, net of original issue discount (Senior Secured Term Loan) | — | 322.8 | |||||||||
| 3.250% Convertible Senior Notes due March 2028 (2028 Convertible Notes) | 320.0 | — | |||||||||
| Finance lease obligations | 23.6 | 29.3 | |||||||||
| Less: Debt issuance costs | (9.8) | (34.8) | |||||||||
| 333.8 | 1,137.8 | ||||||||||
| Less: Current portion of long-term debt | 13.2 | 59.6 | |||||||||
| Long-term debt | $ | 320.6 | $ | 1,078.2 | |||||||
2021 Debt Restructuring
During the first quarter of 2021, the Company completed a series of financing transactions to provide the Company with maturity extensions and covenant relief, while allowing it to maintain near-term operating liquidity. These transactions included a senior notes exchange, a revolving credit facility exchange, various amendments to the Company’s existing debt agreements and a support agreement with the Chapter 11 Cases,Company’s surety bond providers. These transactions were preceded by an organizational realignment in which the Company was requiredformed certain wholly-owned subsidiaries (the Co-Issuers) to pay adequate protection payments of $29.8 million to certain first lien creditorsindirectly own and conduct the operations of the Predecessor company duringCompany’s Wilpinjong Mine in Australia and the period January 1 through April 1, 2017. designation of such entities as unrestricted subsidiaries under the Company’s then-existing credit agreement (Credit Agreement) and senior notes’ indenture.
The adequate protection payments were recorded as “Interest expense” insenior notes exchange involved the consolidated statementstender of operations and ceased upon the Effective Date. The Company did not record interest expense subsequent to the filing of the Bankruptcy Petitions for the majority of non-first lien Predecessor indebtedness, which was automatically stayed in accordance with Section 502(b)(2) of the Bankruptcy Code. The amount of contractual interest stayed was $92.9 million for the period January 1, 2017 through the Effective Date.
Concurrently with the senior secured notes due 2025 (the 2025 Notes and, together withexchange, the Company solicited consents from holders of the 2022 Notes the Senior Notes). The Senior Notes were sold on February 15, 2017 in a private transaction exempt from the registration requirementsto certain proposed amendments to its existing senior notes’ indenture to (i) eliminate substantially all of the Securities Actrestrictive covenants, certain events of 1933.
The Company may redeemalso restructured $216.0 million of existing revolving loans under the 2022 Notes beginning March 31, 2019, in whole or in part, at 103.0% of par, beginning March 31, 2020 at 101.5% of par and beginning March 31, 2021 and thereafter at par. The 2025 Notes may be redeemed, in whole or in part, beginning March 31, 2020 at 104.8% of par, beginning March 31, 2021 at 103.2% of par, beginning March 31, 2022 at 101.6% of par and beginning March 31, 2023 and thereafter at par. In addition, prior to the first date on which the Senior Notes are redeemable at the redemption prices noted above, the Company may also redeem some or all of the Senior Notes at a calculated make-whole premium, plus accrued and unpaid interest.
| Peabody Energy Corporation | ||||||||
Under the amended Credit Agreement, there remain no revolving commitments or revolving loans and charged $0.2 million to “Loss on early debt extinguishment.”the first lien net leverage ratio covenant was eliminated. The notes were subsequently canceled.
Commitments under the Company LC Agreement are jointly and severally and fully and unconditionally guaranteed on a senior secured basis by substantially all of the Company’s material domestic restricted subsidiaries and secured by (a) first priority liens over (1) substantially all of the assets of the Company, and the guarantors, except for certain excluded assets, (2) 100% of the capital stock of each domestic restricted subsidiary of the Company, (3) 100% of the non-voting capital stock of each first tier foreign subsidiary of the Company or a foreign subsidiary holding company and no more than 65% of the voting capital stock of each first tier foreign subsidiary of the Company or a foreign subsidiary holding company, (4) a legal charge of 65% of the voting capital stock and 100% of the non-voting capital stock of Peabody Investments (Gibraltar) Limited and (5) all intercompany debt owed to the Company, or any guarantor, in each case, subject to certain exceptions. The obligations under the Senior Notes are secured on a pari passu basis by the same collateral securing the Credit Agreement (as defined below), subject to certain exceptions.
Completion of the 2021 debt restructuring transactions allowed the Company to finalize the surety transaction support agreement described at Note 20. “Financial Instruments, Guarantees With Off-Balance-Sheet Risk and Other Guarantees.”
2021 Debt Retirements
In March 2021, as a requirement of the senior notes exchange, the Company purchased $22.4 million of the 2024 Peabody Notes at 80% of their accreted value, plus accrued and unpaid interest.
In June 2021, the Company announced an at-the-market equity offering program pursuant to which, as amended, the Company could offer and sell up to 32.5 million shares of its common stock. 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 dividendsproceeds of $269.8 million. Such proceeds were utilized, in part, for the retirement of debt as described below.
During the year ended December 31, 2021, the Company retired $91.4 million of 2024 Peabody Notes, $117.8 million of 2025 Notes and share repurchases. Obligations$61.7 million of its Senior Secured Term Loan primarily through various open market purchases at an aggregate cost of $232.4 million.
Also during the year ended December 31, 2021, the Company completed multiple bilateral transactions with note holders 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. 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 Credit Agreement are securedSecurities Act of 1933, based in part on a pari passurepresentations of holders of the 2022 Notes, the 2025 Notes and the 2024 Peabody Notes, and on the basis bythat the same collateral securingexchange was completed with existing holders of the Senior Notes.
| Peabody Energy Corporation | ||||||||
On March 31, 2022, the Company has repaid $557.0retired the remaining principal balance of 2022 Notes upon maturity for $23.1 million.
During the three months ended March 31, 2022, $62.5 million principal amount of the 2024 Peabody Notes was retired using proceeds from the offering of 2028 Convertible Notes, as further described below, and the remaining $0.1 million principal amount was retired through a mandatory repurchase offer required under the terms of their indenture and the Company LC Agreement. Such mandatory repurchase offers were required when the Company made open market repurchases of its debt. In general, the repurchase offers equated to 25% of the principal amount of priority lien debt repurchased in the preceding quarter at a price equal to the weighted average repurchase price paid over that quarter. In addition to the $0.1 million principal amount of 2024 Peabody Notes repurchased through such offers, the Company repurchased $42.2 million of aggregate priority lien obligations under the original $950.0Company LC Agreement during 2022 at approximately 95%. The repurchases of Company LC Agreement commitments were effected by the posting of $40.1 million loanof collateral with the administrative agent and did not reduce the availability under the facility.
In March 2022, $257.4 million principal amount onof the 2025 Notes was retired using proceeds from the offering of 2028 Convertible Notes, as further described below. The remaining 2025 Notes were retired through an open market repurchase of $11.4 million principal amount at 98.00% in September 2022 and, in accordance with the notes’ indenture, a voluntary prepayment of $66.1 million principal amount at 101.59% in December 2022.
The Senior Secured Term Loan was retired through various open market purchases of $44.1 million principal amount throughout 2022 at an aggregate cost of $42.1 million, scheduled quarterly principal amortization payments of $3.0 million, and, in various installments, including $546.0 million which was voluntarily prepaid. In September 2017,accordance with the Company entered into an amendment toterms of the Credit Agreement, which permitted the Company to add an incremental revolving credit facility in addition to the Company’s ability to add one or more incremental term loan facilities under the Credit Agreement. The incremental revolving credit facility and/or incremental term loan facilities can be in an aggregatea voluntary prepayment of $276.2 million principal amount at par in December 2022.
The 2024 Co-Issuer Notes and the Co-Issuer Term Loans were subject to mandatory prepayment offers at the end of up to $350.0 million plus additional amounts so long aseach six-month period, beginning with June 30, 2021, whereby the Company remains in compliance with Total Leverage Ratio requirements as set forth in the Credit Agreement. The Amendment also made available an additional restricted payment basket that permits additional repurchases, dividends or other distributions with respect to the Company’s common and preferred Stock in an aggregate amount up to $450.0 million so long as the Company’s Fixed Charge Coverage RatioExcess Cash Flow (as defined in the Credit Agreement) is at least 2.00:1.002024 Co-Issuer Notes indenture) generated by the Wilpinjong Mine during each such period could be applied to the principal of such notes and loans on a pro forma basis.
Voluntary repurchases of Co-Issuer Term Loans were permissible through various methods, including a modified Dutch auction process in which the Company could solicit acceptable prices from holders. During the year ended December 31, 2022, the Company solicited bids from all holders of Co-Issuer Term Loans at various dates for the repurchase of the remaining outstanding principal amount, resulting in the valid tender and purchase of $185.9 million principal amount at an aggregate cost of $195.8 million.
The underlying terms of the 2024 Co-Issuer Notes and Co-Issuer Term Loans required parity between the holders of Co-Issuer Term Loans and holders of the 2024 Co-Issuer Notes with respect to repurchase offers such as those undertaken through the auction processes described above. As such, the Company solicited commensurate bids from all holders of 2024 Co-Issuer Notes at various dates during the year ended December 31, 2022 for the repurchase of the remaining outstanding principal amount, resulting in the valid tender and purchase of $147.3 million principal amount at an aggregate cost of $154.1 million.
Subsequent to the Credit Agreement which lowered the interest rate on the Senior Secured Term Loan to its current level of LIBOR plus 2.75%modified Dutch auction processes and eliminated an existing 1.0% LIBOR floor. The amendment also extended the maturity of the Senior Secured Term Loan by three years to 2025 and eliminated previous capital expenditure restriction covenants on both the Senior Secured Term Loan and the incremental revolving credit facility described below. In connection with this amendment,related transactions, the Company voluntarily repaid $46.0prepaid the remaining $28.1 million principal amount of 2024 Co-Issuer Notes and $2.9 million principal on the Senior Securedamount of Co-Issuer Term Loan.
The Company’s various debt issuance costsretirements during 2022 resulted in the realization of $4.7 million. In September 2019,net losses from early debt extinguishment of $34.9 million, excluding the Company entered into an amendment to the Credit Agreement which increased the aggregate commitment amount under the Revolver to $565.0 million and extended the maturity date on $540.0 million of the commitments from November 2020 to September 2023. The maturity date for the remaining $25.0 million commitment is November 2020. The Company incurred $5.7 million of additional debt issuance costsloss recorded in connection with the amendment. The Revolver currently permits loans which bear interest at LIBOR plus 3.25%, as well as lettersissuance of credit which incur combined fees of 3.375% per annum. Unused capacity under the Revolver bears a commitment fee of 0.5% per annum. As a result of the amendment, such loans, letters of credit and unused capacity related to the $540.0 million of extended commitments will bear interest and incur fees at rates dependent upon the Company’s First Lien Leverage Ratio (as defined in the Credit Agreement) beginning in 2020. The Revolver is also subject to a 2.00:1.00 Total Leverage Ratio requirement (as defined by the Credit Agreement), modified to limit unrestricted cash netting to $800.0 million.
| Peabody Energy Corporation | ||||||||
The Company used the proceeds of the offering of the 2028 Convertible Notes to redeem the remaining $62.5 million general basketof its outstanding 2024 Peabody Notes and, an annual aggregate $25.0together with available cash, approximately $257.4 million basket which allows dividendsof its outstanding 2025 Notes, and to pay related premiums, fees and expenses relating to the offering of the 2028 Convertible Notes and the redemptions. The Company capitalized $11.2 million of debt issuance costs related to the offering and recognized a loss on early debt extinguishment of $23.0 million during the three months ended March 31, 2022.
The 2028 Convertible Notes will mature on March 1, 2028, unless earlier converted, redeemed or repurchased in accordance with their terms. The 2028 Convertible Notes bear interest at a rate of 3.250% per year, payable semi-annually in arrears on March 1 and September 1 of each year.
The 2028 Convertible Notes are convertible at the option of the holders only in the following circumstances: (1) during any calendar quarter commencing after the calendar quarter ended June 30, 2022, if the last reported sale price per share of the Company’s common stock repurchases. The paymentexceeds 130% of dividendsthe conversion price for each of at least 20 trading days during the 30 consecutive trading days ending on, and purchasesincluding, the last trading day of the immediately preceding calendar quarter; (2) during the five consecutive business days immediately after any five consecutive trading day period (such five consecutive trading day period, the Measurement Period) in which the trading price per $1,000 principal amount of 2028 Convertible Notes for each trading day of the Measurement Period was less than 98% of the product of the last reported sale price per share of the Company’s common stock on such trading day and the conversion rate on such trading day; (3) upon the occurrence of certain corporate events or distributions on the Company’s common stock; (4) if the Company calls any 2028 Convertible Notes for redemption; and (5) at any time from, and including, September 1, 2027 until the close of business on the second scheduled trading day immediately before the maturity date.
Upon conversion, the Company may satisfy its conversion obligation by paying or delivering, as applicable, cash, shares of the Company’s common stock or a combination of cash and shares of the Company’s common stock, at the Company’s election, in the manner and subject to the terms and conditions provided in the indenture. The initial conversion rate for the 2028 Convertible Notes will be 50.3816 shares of the Company’s common stock per $1,000 principal amount of 2028 Convertible Notes, which represents an initial conversion price of approximately $19.85 per share of the Company’s common stock. The initial conversion price represents a premium of approximately 32.5% to the $14.98 per share closing price of the Company’s common stock on February 24, 2022. The conversion rate is subject to adjustment under this annual aggregate $25.0 million basket are permitted so longcertain circumstances in accordance with the terms of the indenture. If certain corporate events described in the indenture occur prior to the maturity date, or the Company delivers a notice of redemption (as described below), the conversion rate will be increased for a holder who elects to convert its 2028 Convertible Notes in connection with such corporate event or notice of redemption, as the case may be, in certain circumstances.
The Company may not redeem the 2028 Convertible Notes prior to March 1, 2025. The Company may redeem for cash all or any portion of the 2028 Convertible Notes, at its option, on or after March 1, 2025 and on or before the 40th scheduled trading day immediately before the maturity date, at a cash redemption price equal to 100% of the principal amount of the 2028 Convertible Notes to be redeemed, plus accrued and unpaid interest, if any, to, but excluding, the redemption date, but only if the last reported sale price per share of the Company’s Total Leverage Ratio wouldcommon stock exceeds 130% of the conversion price on (1) each of at least 20 trading days, whether or not exceed 1.25:1.00consecutive, during the 30 consecutive trading days ending on, and including, the trading day immediately before the date the Company sends the related redemption notice; and (2) the trading day immediately before the date the Company sends such notice. However, the Company may not redeem less than all of the outstanding 2028 Convertible Notes unless at least $75 million aggregate principal amount of 2028 Convertible Notes are outstanding and not called for redemption as of the time the Company sends the related redemption notice. No sinking fund is provided for the 2028 Convertible Notes.
If the Company undergoes a pro forma basisfundamental change (as defined in the indenture), noteholders may require the Company to repurchase their 2028 Convertible Notes at a cash repurchase price equal to 100% of the principal amount of the 2028 Convertible Notes to be repurchased, plus accrued and unpaid interest, if any, to, but excluding, the fundamental change repurchase date.
| Peabody Energy Corporation | 2022 Form 10-K | F-34 | ||||||
During the fourth quarter of 2022, the Company’s reported common stock prices prompted the conversion feature of the 2028 Convertible Notes. As a result, the 2028 Convertible Notes are convertible at the option of the holders during the first quarter of 2023. The Company cannot currently satisfy the conversion obligation in cash because the terms of the Credit Agreement generally prohibit the Company from retiring unsecured debt with cash. It is the Company’s current intent and Indenture).policy to settle any conversions of 2028 Convertible Notes through shares of its common stock. As such, the 2028 Convertible Notes are not classified as a current obligation in the accompanying consolidated balance sheets. Through February 17, 2023, the Company has not received any conversion requests and does not anticipate receiving any conversion requests in the near term as the market value of the 2028 Convertible Notes exceeds their conversion value. As of December 31, 2022, the if-converted value of the 2028 Convertible Notes exceeded the principal amount by $105.8 million.
Margin Financing Arrangement
In March 2022, the Company entered into a discrete credit agreement which provided for a $150 million unsecured revolving credit facility. The revolving facility was scheduled to mature in April 2025 and bore interest at a rate of 10.0% per annum on drawn amounts. The revolving facility was intended to support the Company’s near-term liquidity requirements, particularly with respect to the cash margin requirements associated with the Company’s coal derivative contracts, which fluctuate depending upon underlying market coal prices. Concurrently with the Credit Agreement, the Company entered into a related agreement for an at-the-market equity offering program for up to $225.0 million of the Company’s common stock.
During the three months ended March 31, 2022, the Company borrowed and repaid $225.0 million under the revolving facility using net proceeds of $222.0 million from at-the-market issuances of 10.1 million shares of common stock and available cash. The Company made no additional borrowings and terminated the facility in August 2022.
Interest Charges
The following table presents the components of the Company’s interest expense related to its indebtedness and financial assurance instruments such as surety bonds and letters of credit. Additionally, the table sets forth the amount of cash paid for interest and the amount of non-cash interest expense primarily related to the amortization of debt issuance costs.
| Year Ended December 31, | |||||||||||||||||
| 2022 | 2021 | 2020 | |||||||||||||||
| (Dollars in millions) | |||||||||||||||||
| Indebtedness | $ | 87.0 | $ | 132.3 | $ | 104.4 | |||||||||||
| Financial assurance instruments | 53.3 | 51.1 | 35.4 | ||||||||||||||
| Interest expense | $ | 140.3 | $ | 183.4 | $ | 139.8 | |||||||||||
| Cash paid for interest | $ | 118.5 | $ | 174.9 | $ | 126.9 | |||||||||||
| Non-cash interest expense | $ | 17.7 | $ | 21.3 | $ | 16.2 | |||||||||||
Covenant Compliance
The Company was compliant with all relevant covenants under its debt agreements at December 31, 2022, including the minimum aggregate liquidity requirement under the Company LC Agreement which requires the Company’s restricted subsidiaries to maintain minimum aggregate liquidity of $125.0 million at the end of each quarter through December 31, 2023.
Finance Lease Obligations
Refer to Note 15.11. “Leases” for additional information associated with the Company’s finance leases, which pertain to the financing of mining equipment used in operations.
(11) Leases |
The Company has operating and finance leases for mining and non-mining equipment, office space and certain other facilities under various non-cancellable agreements. Historically, the majority of the Company’s leases have been accounted for as operating leases. Refer to Note 1. “Summary of Significant Accounting Policies” for the Company’s policies regarding “Leases.”
| Peabody Energy Corporation | 2022 Form 10-K | F-35 | ||||||
The Company and certain of its subsidiaries have guaranteed other subsidiaries’ performance under various lease obligations. Certain lease agreements are subject to the restrictive covenants of the Company’s credit facilities and include cross-acceleration provisions, under which the lessor could require remedies including, but not limited to, immediate recovery of the present value of any remaining lease payments. The Company typically agrees to indemnify lessors for the value of the property or equipment leased, should the property be damaged or lost during the course of the Company’s operations. The Company expects that losses with respect to leased property, if any, may be covered by insurance (subject to deductibles). Aside from indemnification of the lessor for the value of the property leased, the Company’s maximum potential obligations under its leases are equal to the respective future minimum lease payments, and the Company assumes that 0no amounts could be recovered from third parties. In this regard, the Company has recorded provisions amounting to $50.7 million related to the loss of leased equipment at its North Goonyella Mine as described in Note 22. “Other Events.”
The components of lease expense duringfor the year ended December 31, 2019periods presented below were as follows:
| Year Ended December 31, 2019 | |||
| (Dollars in millions) | |||
| Operating lease cost: | |||
| Operating leases | $ | 43.3 | |
| Short-term leases | 49.7 | ||
| Variable leases | 19.1 | ||
| Sublease income | (2.6 | ) | |
| Total operating lease cost | $ | 109.5 | |
| Finance lease cost: | |||
| Amortization of right-of-use assets | $ | 15.3 | |
| Interest on lease liabilities | 1.5 | ||
| Total finance lease cost | $ | 16.8 | |
| Year Ended December 31, | |||||||||||||||||
| 2022 | 2021 | 2020 | |||||||||||||||
| (Dollars in millions) | |||||||||||||||||
| Operating lease cost: | |||||||||||||||||
| Operating leases | $ | 18.9 | $ | 19.8 | $ | 28.8 | |||||||||||
| Short-term leases | 30.6 | 15.5 | 39.1 | ||||||||||||||
| Variable leases | 7.6 | 2.7 | 4.6 | ||||||||||||||
| Sublease income | (1.3) | (1.9) | (2.3) | ||||||||||||||
| Total operating lease cost | $ | 55.8 | $ | 36.1 | $ | 70.2 | |||||||||||
| Finance lease cost: | |||||||||||||||||
| Amortization of right-of-use assets | $ | 6.3 | $ | 5.9 | $ | 3.5 | |||||||||||
| Interest on lease liabilities | 2.1 | 2.7 | 0.8 | ||||||||||||||
| Total finance lease cost | $ | 8.4 | $ | 8.6 | $ | 4.3 | |||||||||||
| Peabody Energy Corporation | ||||||||
Supplemental balance sheet information related to leases at December 31, 20192022 and 2021 was as follows:
| December 31, 2019 | |||
| (Dollars in millions) | |||
| Operating leases: | |||
| Operating lease right-of-use assets | $ | 82.4 | |
| Accounts payable and accrued expenses | $ | 29.6 | |
| Operating lease liabilities, less current portion | 52.8 | ||
| Total operating lease liabilities | $ | 82.4 | |
| Finance leases: | |||
| Property, plant, equipment and mine development | $ | 89.6 | |
| Accumulated depreciation | (45.9 | ) | |
| Property, plant, equipment and mine development, net | $ | 43.7 | |
| Current portion of long-term debt | $ | 14.3 | |
| Long-term debt, less current portion | 0.9 | ||
| Total finance lease liabilities | $ | 15.2 | |
| Weighted average remaining lease term (years) | |||
| Operating leases | 3.8 | ||
| Finance leases | 0.6 | ||
| Weighted average discount rate | |||
| Operating leases | 7.3 | % | |
| Finance leases | 6.0 | % | |
| December 31, | |||||||||||
| 2022 | 2021 | ||||||||||
| (Dollars in millions) | |||||||||||
| Operating leases: | |||||||||||
| Operating lease right-of-use assets | $ | 26.9 | $ | 35.5 | |||||||
| Accounts payable and accrued expenses | $ | 16.8 | $ | 16.4 | |||||||
| Operating lease liabilities, less current portion | 11.0 | 27.2 | |||||||||
| Total operating lease liabilities | $ | 27.8 | $ | 43.6 | |||||||
| Finance leases: | |||||||||||
| Property, plant, equipment and mine development | $ | 36.1 | $ | 32.2 | |||||||
| Accumulated depreciation | (12.6) | (7.4) | |||||||||
| Property, plant, equipment and mine development, net | $ | 23.5 | $ | 24.8 | |||||||
| Current portion of long-term debt | $ | 13.2 | $ | 15.3 | |||||||
| Long-term debt, less current portion | 10.4 | 14.0 | |||||||||
| Total finance lease liabilities | $ | 23.6 | $ | 29.3 | |||||||
| Weighted average remaining lease term (years) | |||||||||||
| Operating leases | 2.0 | ||||||||||
| Finance leases | 6.7 | ||||||||||
| Weighted average discount rate | |||||||||||
| Operating leases | 5.7 | % | |||||||||
| Finance leases | 7.2 | % | |||||||||
Supplemental cash flow information related to leases duringfor the year ended December 31, 2019periods presented below was as follows:
| Year Ended December 31, 2019 | |||
| (Dollars in millions) | |||
| Cash paid for amounts included in the measurement of lease liabilities: | |||
| Operating cash flows for operating leases | $ | 51.0 | |
| Operating cash flows for finance leases | 1.5 | ||
| Financing cash flows for finance leases | 29.6 | ||
| Right-of-use assets obtained in exchange for lease obligations: | |||
| Operating leases | 16.6 | ||
| Finance leases | 1.6 | ||
| Year Ended December 31, | |||||||||||||||||
| 2022 | 2021 | 2020 | |||||||||||||||
| (Dollars in millions) | |||||||||||||||||
| Cash paid for amounts included in the measurement of lease liabilities: | |||||||||||||||||
| Operating cash flows for operating leases | $ | 20.5 | $ | 24.3 | $ | 35.1 | |||||||||||
| Operating cash flows for finance leases | 2.1 | 3.8 | 0.8 | ||||||||||||||
| Financing cash flows for finance leases | 9.3 | 8.2 | 8.9 | ||||||||||||||
| Right-of-use assets obtained in exchange for lease obligations: | |||||||||||||||||
| Operating leases | 13.5 | 7.1 | 16.5 | ||||||||||||||
| Finance leases | 6.4 | 24.4 | 1.6 | ||||||||||||||
| Peabody Energy Corporation | ||||||||
The Company's leases have remaining lease terms ofranging from 1 year to 11.38.3 years, some of whichand may include options to extend the terms, deemed reasonably certain of exercise. Maturitiesas applicable. The contractual maturities of lease liabilities were as follows:
| Period Ending December 31, | Operating Leases | Finance Leases | ||||||
| (Dollars in millions) | ||||||||
| 2020 | $ | 33.7 | $ | 14.5 | ||||
| 2021 | 23.1 | 0.6 | ||||||
| 2022 | 14.1 | 0.2 | ||||||
| 2023 | 12.2 | 0.1 | ||||||
| 2024 | 4.8 | — | ||||||
| 2025 and thereafter | 7.2 | — | ||||||
| Total lease payments | 95.1 | 15.4 | ||||||
| Less imputed interest | (12.7 | ) | (0.2 | ) | ||||
| Total lease liabilities | $ | 82.4 | $ | 15.2 | ||||
| Period Ending December 31, | Operating Leases | Finance Leases | ||||||||||||
| (Dollars in millions) | ||||||||||||||
| 2023 | $ | 18.6 | $ | 14.4 | ||||||||||
| 2024 | 7.4 | 5.7 | ||||||||||||
| 2025 | 1.6 | 4.0 | ||||||||||||
| 2026 | 1.4 | 2.2 | ||||||||||||
| 2027 | 0.3 | 1.0 | ||||||||||||
| 2028 and thereafter | 0.4 | — | ||||||||||||
| Total lease payments | 29.7 | 27.3 | ||||||||||||
| Less imputed interest | (1.9) | (3.7) | ||||||||||||
| Total lease liabilities | $ | 27.8 | $ | 23.6 | ||||||||||
Capital Leases | Operating Leases | Coal Lease and Royalty Obligations | ||||||||||
| Year Ending December 31, | ||||||||||||
| (Dollars in millions) | ||||||||||||
| 2019 | $ | 28.2 | $ | 47.6 | $ | 5.4 | ||||||
| 2020 | 8.0 | 27.6 | 5.5 | |||||||||
| 2021 | 0.4 | 15.9 | 5.6 | |||||||||
| 2022 | 0.4 | 11.8 | 5.4 | |||||||||
| 2023 | 0.5 | 12.1 | 5.5 | |||||||||
| 2024 and thereafter | 8.8 | 12.1 | 36.2 | |||||||||
| Total minimum lease payments | 46.3 | $ | 127.1 | $ | 63.6 | |||||||
| Less interest | 6.3 | |||||||||||
| Present value of minimum capital lease payments | $ | 40.0 | ||||||||||
Reconciliations of the Company’s asset retirement obligations are as follows:
| December 31, | |||||||
| 2019 | 2018 | ||||||
| (Dollars in millions) | |||||||
| Balance at beginning of period | $ | 750.2 | $ | 691.1 | |||
| Liabilities incurred or acquired | — | 16.3 | |||||
| Liabilities settled or disposed | (47.7 | ) | (57.8 | ) | |||
| Accretion expense | 54.1 | 48.5 | |||||
| Revisions to estimates | (4.3 | ) | 52.1 | ||||
| Balance at end of period | $ | 752.3 | $ | 750.2 | |||
| Less: Current portion (included in “Accounts payable and accrued expenses”) | 98.2 | 63.8 | |||||
| Noncurrent obligation (included in “Asset retirement obligations”) | $ | 654.1 | $ | 686.4 | |||
| Balance at end of period — active locations | $ | 525.4 | $ | 671.8 | |||
| Balance at end of period — closed or inactive locations | $ | 226.9 | $ | 78.4 | |||
| December 31, | |||||||||||
| 2022 | 2021 | ||||||||||
| (Dollars in millions) | |||||||||||
| Balance at beginning of period | $ | 719.8 | $ | 728.2 | |||||||
| Liabilities settled or disposed | (51.7) | (72.4) | |||||||||
| Accretion expense | 56.2 | 54.9 | |||||||||
| Revisions to estimates | 25.7 | 9.1 | |||||||||
| Balance at end of period | $ | 750.0 | $ | 719.8 | |||||||
| Less: Current portion (included in “Accounts payable and accrued expenses”) | 84.2 | 65.0 | |||||||||
| Noncurrent obligation (included in “Asset retirement obligations”) | $ | 665.8 | $ | 654.8 | |||||||
| Balance at end of period — active locations | $ | 557.9 | $ | 511.8 | |||||||
| Balance at end of period — closed or inactive locations | $ | 192.1 | $ | 208.0 | |||||||
As of December 31, 20192022 and 2018,2021, the Company had $1,401.7$1,250.1 million and $1,317.0$1,294.7 million, respectively, in surety bonds and bank guarantees outstanding to secure reclamation obligations. Additionally, the Company had $106.1$437.8 million and $142.3$323.0 million, respectively, of letters of credit in support of reclamation obligations as of December 31, 20192022 and 2018.2021. See Note 20. “Financial Instruments, Guarantees With Off-Balance-Sheet Risk and Other Guarantees” for a discussion of cash collateral supporting these reclamation bonding requirements.
(13) Postretirement Health Care and Life Insurance Benefits
The Company currently provides health care and life insurance benefits to qualifying salaried and hourly retirees of its current and certain former subsidiaries and their dependents from benefit plans established by the Company. Plan coverage for health benefits is provided to future hourly and salaried retirees in accordance with the applicable plan document. Life insurance benefits are provided to future hourly retirees in accordance with the applicable labor agreement.
| Successor | Predecessor | |||||||||||||
| Year Ended December 31, 2019 | Year Ended December 31, 2018 | April 2 through December 31, 2017 | January 1 through April 1, 2017 | |||||||||||
| (Dollars in millions) | ||||||||||||||
| Service cost for benefits earned | $ | 4.8 | $ | 8.2 | $ | 6.9 | $ | 2.3 | ||||||
| Interest cost on accumulated postretirement benefit obligation | 25.1 | 28.3 | 24.2 | 8.4 | ||||||||||
| Expected return on plan assets | (0.5 | ) | — | — | — | |||||||||
| Amortization of prior service credit | (8.7 | ) | — | — | (2.3 | ) | ||||||||
| Amortization of actuarial loss | — | — | — | 5.5 | ||||||||||
| Net actuarial loss (gain) | 78.3 | (128.4 | ) | (22.0 | ) | — | ||||||||
| Net periodic postretirement benefit cost | $ | 99.0 | $ | (91.9 | ) | $ | 9.1 | $ | 13.9 | |||||
| Peabody Energy Corporation | ||||||||
| Year Ended December 31, | |||||||||||||||||
| 2022 | 2021 | 2020 | |||||||||||||||
| (Dollars in millions) | |||||||||||||||||
| Service cost for benefits earned | $ | 0.8 | $ | 1.0 | $ | 3.8 | |||||||||||
| Interest cost on accumulated postretirement benefit obligation | 7.0 | 10.5 | 20.2 | ||||||||||||||
| Expected return on plan assets | (0.8) | (1.0) | (1.5) | ||||||||||||||
| Amortization of prior service credit | (53.8) | (46.4) | (17.3) | ||||||||||||||
| Net actuarial (gain) loss | (51.2) | (54.5) | 16.5 | ||||||||||||||
| Net periodic postretirement benefit (credit) cost | $ | (98.0) | $ | (90.4) | $ | 21.7 | |||||||||||
The actuarial gain for all benefit plans in 2022 was primarily due to the Company made a policy electionincrease in the discount rate used to prospectively record amounts attributablemeasure the benefit obligation and favorable impact of claims experience for the year offset by increase in medical trend rate due to inflation as well as expected impact of recently passed Inflation Reduction Act. The actuarial valuation changes currentlygain for all benefit plans in earnings rather than recording such amounts within accumulated other comprehensive income2021 was primarily due to the increase in the discount rate used to measure the benefit obligation, favorable impact of claims experience for the year, and amortizingupdating the mortality base table and improvement scale to expense over applicable time periods.those published by the Society of Actuaries considering the plan’s experience for participants receiving medical benefits under the United Mine Workers of America (UMWA) Coal Act design. The actuarial loss for all benefit plans in 2020 was primarily due to the decrease in the discount rate used to measure the benefit obligation offset by the favorable impact of claims experience for the year and updating the mortality base tables and improvement scales to those published by the Society of Actuaries for all participants except those receiving medical benefits under the UMWA Coal Act design.
The following includes pre-taxpretax amounts recorded in “Accumulated other comprehensive income”:
| Successor | Predecessor | |||||||||
| Year Ended December 31, 2019 | Year Ended December 31, 2018 | January 1 through April 1, 2017 | ||||||||
| (Dollars in millions) | ||||||||||
| Prior service credit arising during year | $ | — | $ | (51.7 | ) | $ | — | |||
| Amortization: | ||||||||||
| Actuarial loss | — | — | (5.5 | ) | ||||||
| Prior service credit | 8.7 | — | 2.3 | |||||||
| Total recorded in “Accumulated other comprehensive income” | $ | 8.7 | $ | (51.7 | ) | $ | (3.2 | ) | ||
| Year Ended December 31, | |||||||||||||||||
| 2022 | 2021 | 2020 | |||||||||||||||
| (Dollars in millions) | |||||||||||||||||
| Prior service credit arising during year | $ | — | $ | (139.5) | $ | (185.4) | |||||||||||
| Amortization: | |||||||||||||||||
| Prior service credit | 53.8 | 46.4 | 17.3 | ||||||||||||||
| Total recorded in “Accumulated other comprehensive income” | $ | 53.8 | $ | (93.1) | $ | (168.1) | |||||||||||
The Company amortizes prior service credit over an amortization period of the average remaining service period to full eligibility for participating employees (4.9 yearsat the time of the plan change or the expected lifetime of participants in the plan. Prior service credits established during 2021 and 5.9 years at January 1, 2020 and 2019, respectively). Prior to April 2, 2017, the Company amortized actuarial gain and loss using a 0% corridor with an amortization period that covered the average remaining service period to full eligibility for participating employees (10.3 years at January 1, 2017).are described below. The estimated prior service credit that will be amortized from accumulated other comprehensive income into net periodic postretirement benefit cost during the year ending December 31, 20202023 is $8.7$53.8 million.
| Peabody Energy Corporation | 2022 Form 10-K | F-39 | ||||||
The following table sets forth the plans’ funded status reconciled with the amounts shown in the consolidated balance sheets:
| December 31, | |||||||
| 2019 | 2018 | ||||||
| (Dollars in millions) | |||||||
| Change in benefit obligation: | |||||||
| Accumulated postretirement benefit obligation at beginning of period | $ | 595.4 | $ | 783.3 | |||
| Service cost | 4.8 | 8.2 | |||||
| Interest cost | 25.1 | 28.3 | |||||
| Participant contributions | 2.3 | 0.5 | |||||
| Plan amendments | — | (51.7 | ) | ||||
| Benefits paid | (47.7 | ) | (44.8 | ) | |||
| Actuarial loss (gain) | 80.0 | (128.4 | ) | ||||
| Accumulated postretirement benefit obligation at end of period | 659.9 | 595.4 | |||||
| Change in plan assets: | |||||||
| Fair value of plan assets at beginning of period | 15.0 | — | |||||
| Actual return on plan assets | 2.2 | — | |||||
| Employer contributions | 62.4 | 59.3 | |||||
| Participant contributions | 2.3 | 0.5 | |||||
| Benefits paid and administrative fees (net of Medicare Part D reimbursements) | (47.7 | ) | (44.8 | ) | |||
| Fair value of plan assets at end of period | 34.2 | 15.0 | |||||
| Funded status at end of period | (625.7 | ) | (580.4 | ) | |||
| Less: Current portion (included in “Accounts payable and accrued expenses”) | 32.3 | 32.7 | |||||
| Noncurrent obligation (included in “Accrued postretirement benefit costs”) | $ | (593.4 | ) | $ | (547.7 | ) | |
| December 31, | |||||||||||
| 2022 | 2021 | ||||||||||
| (Dollars in millions) | |||||||||||
| Change in benefit obligation: | |||||||||||
| Accumulated postretirement benefit obligation at beginning of period | $ | 258.7 | $ | 476.6 | |||||||
| Service cost | 0.8 | 1.0 | |||||||||
| Interest cost | 7.0 | 10.5 | |||||||||
| Participant contributions | — | 0.1 | |||||||||
| Plan amendments | — | (139.5) | |||||||||
| Benefits paid and administrative fees (net of Medicare Part D reimbursements) | (21.2) | (34.5) | |||||||||
| Actuarial gain | (55.4) | (55.5) | |||||||||
| Accumulated postretirement benefit obligation at end of period | 189.9 | 258.7 | |||||||||
| Change in plan assets: | |||||||||||
| Fair value of plan assets at beginning of period | 26.1 | 33.7 | |||||||||
| Actual return on plan assets | (3.4) | — | |||||||||
| Employer contributions | 15.9 | 26.8 | |||||||||
| Participant contributions | — | 0.1 | |||||||||
| Benefits paid and administrative fees (net of Medicare Part D reimbursements) | (21.2) | (34.5) | |||||||||
| Fair value of plan assets at end of period | 17.4 | 26.1 | |||||||||
| Funded status at end of period | (172.5) | (232.6) | |||||||||
| Less: Current portion (included in “Accounts payable and accrued expenses”) | 16.0 | 20.5 | |||||||||
| Noncurrent obligation (included in “Accrued postretirement benefit costs”) | $ | (156.5) | $ | (212.1) | |||||||
retirees. The impact of the amendmentchanges on future benefits reduced the Company’s accumulated postretirement benefit obligation by $51.7$139.5 million. Of that amount, $50.2 millionThe reduction was attributable to the annualelimination of health care benefits and the maximum balance limits and $1.5 million was attributable to the limitation of eligibility based on age and service criteria.for certain represented retirees. The reduction in liability was recorded with an offsetting balance in accumulated“Accumulated other comprehensive income, netincome” and is being amortized to earnings based upon the estimated remaining life expectancies of certain plan participants (13.0 years and 14.0 years were the remaining amortization periods at January 1, 2023 and 2022, respectively).
In September 2020, the Company announced changes to its postretirement health care benefit plans for non-represented employees and retirees. Effective January 1, 2021, the Company no longer subsidizes medical costs for Medicare eligible individuals or provides life insurance to salaried and hourly non-union retirees. The Company provides non-Medicare eligible salaried and hourly non-union retirees and eligible dependents a deferred tax provision,health reimbursement arrangement. There were no changes to benefits for represented participants. The impact of $44.6the changes on future benefits reduced the Company’s accumulated postretirement benefit obligation by $185.4 million. The reduction was attributable to the elimination of health care benefits upon covered individuals’ attainment of Medicare eligibility and the elimination of life insurance benefits for certain non-represented participants. The reduction in liability was recorded with an offsetting balance in “Accumulated other comprehensive income.” The $174.5 million whichreduction for elimination of health care benefits upon attainment of Medicare eligibility for salaried and non-union hourly retirees and eligible dependents is being amortized to earnings over an average remaining service period to full eligibility for participating employees (2.9 years and 3.9 years were the remaining amortization periods at January 1, 2023 and 2022, respectively). The remaining $10.9 million for the elimination of 5.9 years.life insurance benefits and elimination of health care benefits upon attainment of Medicare eligibility for select non-union retirees is being amortized to earnings over the average remaining life expectancy of the affected plan (8.5 years and 9.5 years were the remaining amortization periods at January 1, 2023 and 2022, respectively).
A prior service credit established in December 2018 is being amortized to earnings over an average remaining service period to full eligibility for participating employees (1.9 years and 2.9 years were the remaining amortization periods at January 1, 2023 and 2022, respectively).
| Peabody Energy Corporation | 2022 Form 10-K | F-40 | ||||||
The weighted-average assumptions used to determine the benefit obligations for the plans as of the end of each year were as follows:
| December 31, | |||||
| 2019 | 2018 | ||||
| Discount rate | 3.40 | % | 4.35 | % | |
| Measurement date | December 31, 2019 | December 31, 2018 | |||
| December 31, | |||||||||||
| 2022 | 2021 | ||||||||||
| Discount rate | 5.70 | % | 2.84 | % | |||||||
| Measurement date | December 31, 2022 | December 31, 2021 | |||||||||
The weighted-average assumptions used to determine net periodic postretirement benefit (credit) cost for the plans during each period were as follows:
| Successor | Predecessor | |||||||||
| Year Ended December 31, 2019 | Year Ended December 31, 2018 | April 2 through December 31, 2017 | January 1 through April 1, 2017 | |||||||
| Discount rate | 4.35 | % | 3.70 | % | 4.10 | % | 4.15 | % | ||
| Expected long-term return on plan assets | 5.00 | % | — | % | — | % | — | % | ||
| Measurement date | December 31, 2018 | December 31, 2017 | April 1, 2017 | December 31, 2016 | ||||||
| Year Ended December 31, | |||||||||||||||||
| 2022 | 2021 | 2020 | |||||||||||||||
| Discount rate | 2.84 | % | 2.55 | % | 3.40 | % | |||||||||||
| Expected long-term return on plan assets (pretax) | 5.75 | % | 5.75 | % | 7.00 | % | |||||||||||
| Measurement date | December 31, 2021 | December 31, 2020 | December 31, 2019 | ||||||||||||||
The expected rate of return on plan assets is determined by taking into consideration expected long-term returns associated with each major asset class based on long-term historical ranges, inflation assumptions and the expected net value from active management of the assets based on actual results. Effective January 1, 2020The asset allocation of plan assets and long-term capital market expectations remain unchanged from December 31, 2021, therefore the Company increased itsCompany’s expected pretax rate of return on plan assets from 5.00% to 7.00% reflecting the impact of the Company’s asset allocation and capital market expectations.will remain at 5.75% for 2023.
The accumulated postretirement benefit obligation exceeded plan assets for all plans as of December 31, 20192022 and 2018.2021. The accumulated postretirement benefit obligation for all plans was $659.9$189.9 million and $595.4$258.7 million as of December 31, 20192022 and 2018,2021, respectively.
The following presents information about the assumed health care cost trend rate:
| Year Ended December 31, | |||||
| 2019 | 2018 | ||||
| Pre-Medicare: | |||||
| Health care cost trend rate assumed for next year | 6.75 | % | 6.55 | % | |
| Rate to which the cost trend is assumed to decline (the ultimate trend rate) | 4.75 | % | 4.75 | % | |
| Year that the rate reaches the ultimate trend rate | 2023 | 2023 | |||
| Post-Medicare: | |||||
| Health care cost trend rate assumed for next year | 6.35 | % | 6.15 | % | |
| Rate to which the cost trend is assumed to decline (the ultimate trend rate) | 4.75 | % | 4.75 | % | |
| Year that the rate reaches the ultimate trend rate | 2023 | 2023 | |||
One Percentage- Point Increase | One Percentage- Point Decrease | ||||||
| (Dollars in millions) | |||||||
| Effect on total service and interest cost components | $ | 2.5 | $ | (2.3 | ) | ||
| Effect on total postretirement benefit obligation | $ | 57.3 | $ | (50.9 | ) | ||
| Year Ended December 31, | |||||||||||
| 2022 | 2021 | ||||||||||
| Pre-Medicare: | |||||||||||
| Health care cost trend rate assumed for next year | 7.00 | % | 6.00 | % | |||||||
| Rate to which the cost trend is assumed to decline (the ultimate trend rate) | 4.75 | % | 4.75 | % | |||||||
| Year that the rate reaches the ultimate trend rate | 2032 | 2027 | |||||||||
| Post-Medicare: | |||||||||||
| Health care cost trend rate assumed for next year | 6.75 | % | 5.75 | % | |||||||
| Rate to which the cost trend is assumed to decline (the ultimate trend rate) | 4.75 | % | 4.75 | % | |||||||
| Year that the rate reaches the ultimate trend rate | 2032 | 2027 | |||||||||
Plan Assets
The Company has established twomaintains a Voluntary EmployeesEmployees’ Beneficiary Association (VEBA) truststrust to pre-fund a portion of benefits for non-represented and represented retirees. Assets of the Peabody Investments Corp. Non-Represented Retiree VEBA Trust (the Non-Represented Trust) are invested in accordance with the investment policy established by the Peabody VEBA Retirement Committee after consultation with outside investment advisors and actuaries. TheAs of December 31, 2022 and 2021, the asset allocation strategy for the Non-Represented trustTrust is 50%30% in equity and 50%70% in fixed income assets, which are designed to balance the needs of having growth and stability in the portfolio. Thisassets. The asset strategy may vary over time based on changes in the status of the Non-Represented Plan, the Company’s risk posture and other factors. The Peabody Holding Company LLC Represented Retiree VEBA Trust (the Represented Trust) is unfunded at December 31, 2019 and 2018.
A financial instrument’s level within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. Following is a description of the valuation techniques and inputs used for investments measured at fair value, including the general classification of such investments pursuant to the valuation hierarchy.
| Peabody Energy Corporation | 2022 Form 10-K | F-41 | ||||||
U.S. equity securitiessecurities.: The Non-Represented Trust invests in U.S. equity securities for growth and diversification. Investment vehicles include various domestic large-cap publicly traded common stocks and mutual funds.stocks. All common stocks are traded on a national securities exchange and are valued at quoted market prices in active markets and accordingly classified within Level 1 of the valuation hierarchy. The mutual funds are traded on a national securities exchange in an active market, are valued using daily publicly quoted net asset value (NAV) prices and accordingly classified within Level 1 of the valuation hierarchy.
International equity securities. The Non-Represented Trust invests in international equity securities for growth and diversification. Investment vehicles include various international publicly traded common stocks, exchange traded funds and mutual funds. All common stocks are traded on a national securities exchange and are valued at quoted market prices in active markets and accordingly classified within Level 1 of the valuation hierarchy. The exchange traded funds and mutual funds are traded on a national securities exchange in an active market, are valued using daily publicly quoted NAVnet asset value (NAV) prices and accordingly classified within Level 1 of the valuation hierarchy.
Corporate bonds. The Non-Represented Trust invests in corporate bonds for diversification, volatility reduction of equity securities and to provide a hedge to interest rate movements affecting liabilities. Investment types are predominantly investment-grade corporate bonds. Fair value for these securities is provided by a third-party pricing service that utilizes various inputs such as benchmark yields, reported trades, broker/dealer quotes, issuer spreads and benchmark securities as well as other relevant economic measures. Corporate bonds are classified within the Level 2 valuation hierarchy since fair value inputs are derived prices in active markets and the bonds are not traded on a national securities exchange.
U.S. government securities. The Non-Represented Trust invests in U.S. government securities for diversification, volatility reduction of equity securities and to provide a hedge to interest rate movements affecting liabilities. Investment types are predominantly U.S. government bonds, notes, agency securities and municipal bonds. Fair value for these securities is provided by a third-party pricing service that utilizes various inputs such as benchmark yields, reported trades, broker/dealer quotes, issuer spreads and benchmark securities as well as other relevant economic measures. If fair value is based on quoted prices in active markets and traded on a national securities exchange, U.S. government securities are classified within the Level 1 valuation hierarchy; otherwise, U.S. government securities are classified within the Level 2 valuation hierarchy.
Cash funds. The Non-Represented Trust invests in cash funds to manage liquidity resulting from payment of participant benefits and certain administrative fees. The investment consists of anon-interest bearing cash funds and U.S. Governmentgovernment money market fund which isare classified within the Level 1 valuation hierarchy.
The methods described above may produce a fair value calculation that may not be indicative of net realizable value or reflective of future fair values. Furthermore, while the Company believes its valuation methods are appropriate and consistent with other market participants, the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different fair value measurement at the reporting date. The inputs or methodologies used for valuing investments are not necessarily an indication of the risk associated with investing in those investments.
The following tables present the fair value of assets in the Non-Represented Trust by asset category and by fair value hierarchy:
| December 31, 2022 | |||||||||||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||
| (Dollars in millions) | |||||||||||||||||||||||
| U.S. equity securities | $ | 3.7 | $ | — | $ | — | $ | 3.7 | |||||||||||||||
| International equity securities | 1.1 | — | — | 1.1 | |||||||||||||||||||
| Corporate bonds | — | 7.1 | — | 7.1 | |||||||||||||||||||
| U.S. government securities | 2.0 | 3.0 | — | 5.0 | |||||||||||||||||||
| Cash funds | 0.5 | — | — | 0.5 | |||||||||||||||||||
| Total assets at fair value | $ | 7.3 | $ | 10.1 | $ | — | $ | 17.4 | |||||||||||||||
| December 31, 2019 | |||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | ||||||||||||
| (Dollars in millions) | |||||||||||||||
| U.S. equity securities | $ | 13.0 | $ | — | $ | — | $ | 13.0 | |||||||
| International equity securities | 4.0 | — | — | 4.0 | |||||||||||
| Corporate bonds | — | 9.2 | — | 9.2 | |||||||||||
| U.S. government securities | 2.6 | 4.5 | — | 7.1 | |||||||||||
| Cash funds | 0.9 | — | — | 0.9 | |||||||||||
| Total assets at fair value | $ | 20.5 | $ | 13.7 | $ | — | $ | 34.2 | |||||||
| Peabody Energy Corporation | 2022 Form 10-K | F-42 | ||||||
PEABODY ENERGY CORPORATION
| December 31, 2018 | |||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | ||||||||||||
| (Dollars in millions) | |||||||||||||||
| Cash funds | $ | 15.0 | $ | — | $ | — | $ | 15.0 | |||||||
| Total assets at fair value | $ | 15.0 | $ | — | $ | — | $ | 15.0 | |||||||
| December 31, 2021 | |||||||||||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||
| (Dollars in millions) | |||||||||||||||||||||||
| U.S. equity securities | $ | 5.7 | $ | — | $ | — | $ | 5.7 | |||||||||||||||
| International equity securities | 2.0 | — | — | 2.0 | |||||||||||||||||||
| Corporate bonds | — | 10.1 | — | 10.1 | |||||||||||||||||||
| U.S. government securities | 3.1 | 3.8 | — | 6.9 | |||||||||||||||||||
| Cash funds | 1.4 | — | — | 1.4 | |||||||||||||||||||
| Total assets at fair value | $ | 12.2 | $ | 13.9 | $ | — | $ | 26.1 | |||||||||||||||
Contributions
Annual contributions to the Non-Represented Trust are discretionary. During the year ended December 31, 2019,2022, the Company made a pre-funding contribution of $17.0 millionno contributions to the Non-Represented Trust.trust.
Estimated Future Benefit Payments
The following benefit payments (net of retiree contributions)contributions and Medicare Part D reimbursements), which reflect expected future service, as appropriate, are expected to be paid by the Company:Company or satisfied from Non-Represented Trust assets:
Postretirement Benefits | |||
| (Dollars in millions) | |||
| 2020 | $ | 46.1 | |
| 2021 | 46.0 | ||
| 2022 | 45.6 | ||
| 2023 | 44.9 | ||
| 2024 | 44.1 | ||
| Years 2025-2029 | 205.8 | ||
| Postretirement Benefits | |||||
| (Dollars in millions) | |||||
| 2023 | $ | 23.1 | |||
| 2024 | 22.3 | ||||
| 2025 | 21.1 | ||||
| 2026 | 20.1 | ||||
| 2027 | 18.9 | ||||
| Years 2028-2032 | 75.7 | ||||
One of the Company’s subsidiaries, Peabody Investments Corp. (PIC), sponsors a defined benefit pension plan covering certain U.S. salaried employees and eligible hourly employees at certain PIC subsidiaries (the Peabody Plan). A subsidiary of PIC also has a defined benefit pension plan covering eligible employees who are represented by the UMWA under the Western Surface Agreement (the Western Plan). Prior to April 2, 2017, PIC also sponsored an unfunded supplemental retirement plan to provide senior managementPlan and together with benefits in excess of limits under the federal tax law (collectively,Peabody Plan, the Pension Plans).
Effective May 31, 2008, the Peabody Plan was frozen in its entirety for both participation and benefit accrual purposes. TheIn 2020, the Company adopted an enhanced savings plan contribution structureannounced a program to offer a voluntary lump-sum pension payout to eligible active salaried employees and former salaried employees in lieu of benefits formerly accrued under the Peabody Plan. In November 2017,Plan which would settle the Company purchasedCompany’s obligation to them. The program provided participants with a grouplimited time opportunity to elect to receive a lump-sum settlement of their pension benefit or begin to receive their benefit in the form of a monthly annuity contract from an insurance company to pay future pension benefits to approximately 1,950 retirees and beneficiaries of the Peabody Plan.in December 2020. As a resultpart of this transaction,voluntary lump-sum program, the Company settled $71.4$51.6 million of its pension obligation,obligations for active salaried employees and former salaried employees in the Peabody Plan with an equal amount paid from plan assets, andassets. As a result, the Company recorded a settlement chargegain of $2.1$2.7 million during the period April 2 throughyear ended December 31, 2017.
| Successor | Predecessor | |||||||||||||
| Year Ended December 31, 2019 | Year Ended December 31, 2018 | April 2 through December 31, 2017 | January 1 through April 1, 2017 | |||||||||||
| (Dollars in millions) | ||||||||||||||
| Service cost for benefits earned | $ | 2.0 | $ | 2.3 | $ | 1.6 | $ | 0.6 | ||||||
| Interest cost on projected benefit obligation | 33.5 | 31.4 | 28.0 | 9.7 | ||||||||||
| Expected return on plan assets | (31.4 | ) | (42.8 | ) | (33.5 | ) | (11.0 | ) | ||||||
| Amortization of prior service cost | — | — | — | 0.1 | ||||||||||
| Amortization of net actuarial losses | — | — | — | 6.3 | ||||||||||
| Settlement charge | — | — | 2.1 | — | ||||||||||
| Net actuarial (gain) loss | (16.6 | ) | 4.2 | (23.5 | ) | — | ||||||||
| Net periodic pension (benefit) cost | $ | (12.5 | ) | $ | (4.9 | ) | $ | (25.3 | ) | $ | 5.7 | |||
| Predecessor | |||
| January 1 through April 1, 2017 | |||
| (Dollars in millions) | |||
| Amortization: | |||
| Net actuarial loss | $ | (6.3 | ) |
| Prior service cost | (0.1 | ) | |
| Total recorded in “Accumulated other comprehensive income” | $ | (6.4 | ) |
| Peabody Energy Corporation | ||||||||
In May 2022, the Board of Directors of PIC approved the termination of the Peabody Plan effective July 31, 2022. In June 2022, the Peabody Plan’s participants were notified of the Peabody Plan termination and the Peabody Plan filed an application with the Internal Revenue Service to request a determination as to the qualified status under §401(a) of the Internal Revenue Code of 1986 with respect to the amendment and termination of the Peabody Plan. As part of the plan termination process, benefits will be distributed to participants or transferred to an insurance company. Anticipated asset distribution, via voluntary lump sum payouts for active and deferred participants, is expected in the first half of 2023, following which participants not electing a lump sum and all participants in payment status will be transferred to a highly qualified insurance company.
Net periodic pension cost (credit) included the following components:
| Year Ended December 31, | |||||||||||||||||
| 2022 | 2021 | 2020 | |||||||||||||||
| (Dollars in millions) | |||||||||||||||||
| Service cost for benefits earned | $ | 0.1 | $ | 0.2 | $ | 0.3 | |||||||||||
| Interest cost on projected benefit obligation | 21.4 | 20.4 | 28.0 | ||||||||||||||
| Expected return on plan assets | (23.8) | (22.9) | (29.7) | ||||||||||||||
| Settlement | — | — | (2.7) | ||||||||||||||
| Net actuarial loss (gain) | 20.6 | 12.7 | (25.6) | ||||||||||||||
| Net periodic pension cost (credit) | $ | 18.3 | $ | 10.4 | $ | (29.7) | |||||||||||
The actuarial loss for all pension plans in 2022 was primarily due to actual returns on plan assets lower than expected returns for the year and the premium paid to Prudential to purchase the GAC, offset by the increase in the discount rate used to measure the benefit obligation. The actuarial loss for all pension plans in 2021 was primarily due to actual returns on plan assets lower than expected returns for the year, offset by the increase in the discount rate used to measure the benefit obligation. The actuarial gain for all pension plans in 2020 was primarily due to actual returns on plan assets exceeding the expected returns for the year and the favorable impact of updating the mortality base tables and improvement scales to those published by the Society of Actuaries, offset by the decline in the discount rate used to measure the benefit obligation.
| Peabody Energy Corporation | 2022 Form 10-K | F-44 | ||||||
The following summarizes the change in benefit obligation, change in plan assets and funded status of the Pension Plans:
| December 31, | |||||||
| 2019 | 2018 | ||||||
| (Dollars in millions) | |||||||
| Change in benefit obligation: | |||||||
| Projected benefit obligation at beginning of period | $ | 795.9 | $ | 874.6 | |||
| Service cost | 2.0 | 2.3 | |||||
| Interest cost | 33.5 | 31.4 | |||||
| Benefits paid | (55.6 | ) | (55.1 | ) | |||
| Actuarial loss (gain) | 78.0 | (57.3 | ) | ||||
| Projected benefit obligation at end of period | 853.8 | 795.9 | |||||
| Change in plan assets: | |||||||
| Fair value of plan assets at beginning of period | 764.8 | 776.6 | |||||
| Actual return on plan assets | 126.0 | (18.7 | ) | ||||
| Employer contributions | 20.0 | 62.0 | |||||
| Benefits paid | (55.6 | ) | (55.1 | ) | |||
| Fair value of plan assets at end of period | 855.2 | 764.8 | |||||
| Funded status at end of period | $ | 1.4 | $ | (31.1 | ) | ||
| Amounts recognized in the consolidated balance sheets: | |||||||
| Noncurrent asset (included in “Investments and other assets”) | $ | 13.4 | $ | — | |||
| Noncurrent obligation (included in “Other noncurrent liabilities”) | (12.0 | ) | (31.1 | ) | |||
| Net amount recognized | $ | 1.4 | $ | (31.1 | ) | ||
| December 31, | |||||||||||
| 2022 | 2021 | ||||||||||
| (Dollars in millions) | |||||||||||
| Change in benefit obligation: | |||||||||||
| Projected benefit obligation at beginning of period | $ | 751.7 | $ | 816.4 | |||||||
| Service cost | 0.1 | 0.2 | |||||||||
| Interest cost | 21.4 | 20.4 | |||||||||
| Benefits paid | (55.1) | (55.9) | |||||||||
| Actuarial gain | (137.2) | (29.4) | |||||||||
| Projected benefit obligation at end of period | 580.9 | 751.7 | |||||||||
| Change in plan assets: | |||||||||||
| Fair value of plan assets at beginning of period | 772.4 | 847.5 | |||||||||
| Actual return on plan assets | (134.0) | (19.2) | |||||||||
| Benefits paid | (55.1) | (55.9) | |||||||||
| Fair value of plan assets at end of period | 583.3 | 772.4 | |||||||||
| Funded status at end of period | $ | 2.4 | $ | 20.7 | |||||||
| Amounts recognized in the consolidated balance sheets: | |||||||||||
| Noncurrent asset (included in “Investments and other assets”) | $ | 9.9 | $ | 28.5 | |||||||
| Noncurrent obligation (included in “Other noncurrent liabilities”) | (7.5) | (7.8) | |||||||||
| Net amount recognized | $ | 2.4 | $ | 20.7 | |||||||
The weighted-average assumptions used to determine the benefit obligations as of the end of each year were as follows:
| December 31, | |||||
| 2019 | 2018 | ||||
| Discount rate | 3.40 | % | 4.35 | % | |
| Measurement date | December 31, 2019 | December 31, 2018 | |||
| December 31, | |||||||||||
| 2022 | 2021 | ||||||||||
| Discount rate | 5.44 | % | 2.95 | % | |||||||
| Measurement date | December 31, 2022 | December 31, 2021 | |||||||||
The weighted-average assumptions used to determine net periodic pension (benefit) cost (credit) during each period were as follows:
| Successor | Predecessor | |||||||||
| Year Ended December 31, 2019 | Year Ended December 31, 2018 | April 2 through December 31, 2017 | January 1 through April 1, 2017 | |||||||
| Discount rate | 4.35 | % | 3.70 | % | 4.10 | % | 4.15 | % | ||
| Expected long-term return on plan assets | 4.20 | % | 5.65 | % | 5.90 | % | 5.90 | % | ||
| Measurement date | December 31, 2018 | December 31, 2017 | April 1, 2017 | December 31, 2016 | ||||||
| Year Ended December 31, | |||||||||||||||||
| 2022 | 2021 | 2020 | |||||||||||||||
| Discount rate | 2.95 | % | 2.60 | % | 3.40 | % | |||||||||||
| Expected long-term return on plan assets | 3.20 | % | 2.80 | % | 3.60 | % | |||||||||||
| Measurement date | December 31, 2021 | December 31, 2020 | December 31, 2019 | ||||||||||||||
The expected rate of return on plan assets is determined by taking into consideration expected long-term returns associated with each major asset class based on long-term historical ranges, inflation assumptions and the expected net value from active management of the assets based on actual results. Effective January 1, 2020,2023, the Company loweredraised its expected rate of return on plan assets from 4.20%3.20% to 3.60%4.90% and 4.65% for the Peabody Plan and Western Plan; respectively, reflecting the impact of the Company’sPlans’ asset allocationallocations and capital market expectations.
| Peabody Energy Corporation | ||||||||
Assets of the Pension Plans
Assets of the PIC Master Trust (the Master Trust) are invested in accordance with investment guidelines established by the Peabody Plan Retirement Committee and the Peabody Western Plan Retirement Committee (collectively, the Retirement Committees) after consultation with outside investment advisors and actuaries.
The asset allocation targets have been set with the expectation that the assets of the Master Trust will be managed with an appropriate level of risk to fund each Pension Plan’s expected liabilities. To determine the appropriate target asset allocations, the Retirement Committees consider the demographics of each Pension Plan’s participants, the funded status of each Pension Plan, the business and financial profile of the Company and other associated risk preferences. These allocation targets are reviewed by the Retirement Committees on a regular basis and revised as necessary. As a result of discretionary contributions made in recent years, the Pension Plans have become nearly fully funded and therefore, as of December 31, 20192022 and 2018,2021, the Master Trust investment portfolio reflected the Company’s target asset mix of 100% fixed income investments. Master Trust assets also include investments in various real estate holdings through limited partnerships representing approximately less than 1% and 1% of total Master Trust assets as of both December 31, 20192022 and 2018, respectively.2021. The Retirement Committees’ intention is to liquidate these real estate holdings when allowable per the terms of the limited partnership agreements. Generally, dissolution and liquidation of the limited partnerships is required before the Master Trust’s real estate holdings can be liquidated and is estimated to occur at various times through 2021.liquidated.
Assets of the Master Trust are under management by third-party investment managers, which are selected and monitored by the Retirement Committees. Specific investment guidelines have been established by the Retirement Committees for each major asset class including performance benchmarks, allowable and prohibited investment types and concentration limits. In general, investment guidelines do not permit leveraging the assets held in the Master Trust. However, investment managers may employ various strategies and derivative instruments in establishing overall portfolio characteristics consistent with the guidelines and investment objectives established by the Retirement Committees for their portfolios. Fixed income investment guidelines only allow for exchange-traded derivatives if the investment manager deems the derivative vehicle to be more attractive than a similar direct investment in an underlying cash market or to manage the duration of the fixed income portfolio.
A financial instrument’s level within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. Following is a description of the valuation techniques and inputs used for investments measured at fair value, including the general classification of such investments pursuant to the valuation hierarchy.
Corporate bonds. The Master Trust invests in corporate bonds for diversification and to provide a hedge to interest rate movements affecting liabilities. Investment types are predominantly investment-grade corporate bonds. Fair value for these securities is provided by a third-party pricing service that utilizes various inputs such as benchmark yields, reported trades, broker/dealer quotes, issuer spreads and benchmark securities as well as other relevant economic measures. Corporate bonds are classified within the Level 2 valuation hierarchy since fair value inputs are derived prices in active markets and the bonds are not traded on a national securities exchange.
U.S. government securities. The Master Trust invests in U.S. government securities for diversification and to provide a hedge to interest rate movements affecting liabilities. Investment types are predominantly U.S. government bonds, agency securities and municipal bonds. Fair value for these securities is provided by a third-party pricing service that utilizes various inputs such as benchmark yields, reported trades, broker/dealer quotes, issuer spreads and benchmark securities as well as other relevant economic measures. If fair value is based on quoted prices in active markets and traded on a national securities exchange, U.S. government securities are classified within the Level 1 valuation hierarchy; otherwise, U.S. government securities are classified within the Level 2 valuation hierarchy.
International government securities. The Master Trust invests in international government securities for diversification and to provide a hedge to interest rate movements affecting liabilities. Investment types are predominantly non-U.S. government bonds. Fair value for these securities is provided by a third-party pricing service that utilizes various inputs such as benchmark yields, reported trades, broker/dealer quotes, issuer spreads and benchmark securities as well as other relevant economic measures. International government securities are classified within the Level 2 valuation hierarchy since fair value inputs are derived prices in active markets and the bonds are not traded on a national securities exchange.
Asset-backed securities. The Master Trust invests in asset-backed securities for diversification and to provide a hedge to interest rate movements affecting liabilities. Investment types are predominately mortgage-backed securities. Asset-backed securities are classified within the Level 2 valuation hierarchy since fair value inputs are derived prices in active markets and the investments are not traded on a national securities exchange.
| Peabody Energy Corporation | ||||||||
Cash funds. The Master Trust invests in cash funds to manage liquidity resulting from payment of participant benefits and certain administrative fees. Investment vehicles primarily include a non-interest bearing cash fund with an earnings credit allowance feature, various exchange-traded derivative instruments consisting of futures and interest rate swap agreements used to manage the duration of certain liability-hedging investments. The non-interest bearing cash fund is classified within the Level 1 valuation hierarchy. Exchange traded derivatives, such as options and futures, for which market quotations are readily available, are valued at the last reported sale price or official closing price on the primary market or exchange on which they are traded and are classified within the Level 1 valuation hierarchy.
Group annuity contract. The Master Trust invests in a buy-in GAC to provide a hedge to interest rate movements affecting liabilities. The GAC consists of a nonparticipating single premium group annuity contract. The initial value of the GAC was equal to the premium paid to secure the contract and is adjusted each reporting period to reflect the estimated fair value of the premium that would be paid for such a contract at that time. Since there are no observable inputs associated with the valuation, the GAC is classified within the Level 3 valuation hierarchy.
Real estate interests. The Master Trust invests in real estate interests for diversification. Investments in real estate represent interests in several limited partnerships, which invest in various real estate properties. Interests in real estate are valued using various methodologies, including independent third party appraisals; fair value measurements are not developed by the Company. For some investments, little market activity may exist and determination of fair value is then based on the best information available in the circumstances. This involves a significant degree of judgment by taking into consideration a combination of internal and external factors. Accordingly, interests in real estate are classified within the Level 3 valuation hierarchy. Some limited partnerships issue dividends to their investors in the form of cash distributions that the Pension Plans invest elsewhere within the Master Trust.
Private mutual funds. The Master Trust invests in mutual funds for growth and diversification. Investment vehicles include an institutional fund that holds a diversified portfolio of long-duration corporate fixed income investments (Corporate Bond Fund). The Corporate Bond Fund is not traded on a national securities exchange and is valued at NAV, the practical expedient to estimate fair value.
The methods described above may produce a fair value calculation that may not be indicative of net realizable value or reflective of future fair values. Furthermore, while the Company believes its valuation methods are appropriate and consistent with other market participants, the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different fair value measurement at the reporting date. The inputs or methodologies used for valuing investments are not necessarily an indication of the risk associated with investing in those investments.
The following tables present the fair value of assets in the Master Trust by asset category and by fair value hierarchy:
| December 31, 2019 | |||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | ||||||||||||
| (Dollars in millions) | |||||||||||||||
| Corporate bonds | $ | — | $ | 598.3 | $ | — | $ | 598.3 | |||||||
| U.S. government securities | 135.9 | 19.0 | — | 154.9 | |||||||||||
| International government securities | — | 18.2 | — | 18.2 | |||||||||||
| Asset-backed securities | — | 3.4 | — | 3.4 | |||||||||||
| Cash funds | 33.2 | — | — | 33.2 | |||||||||||
| Real estate interests | — | — | 4.1 | 4.1 | |||||||||||
| Total assets at fair value | $ | 169.1 | $ | 638.9 | $ | 4.1 | 812.1 | ||||||||
Assets measured at net asset value practical expedient (1) | |||||||||||||||
| Private mutual funds | 43.1 | ||||||||||||||
| Total plan assets | $ | 855.2 | |||||||||||||
| December 31, 2022 | |||||||||||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||
| (Dollars in millions) | |||||||||||||||||||||||
| Corporate bonds | $ | — | $ | 67.2 | $ | — | $ | 67.2 | |||||||||||||||
| U.S. government securities | 23.3 | 2.8 | — | 26.1 | |||||||||||||||||||
| International government securities | — | 2.0 | — | 2.0 | |||||||||||||||||||
| Asset-backed securities | — | 0.7 | — | 0.7 | |||||||||||||||||||
| Cash funds | 9.8 | — | — | 9.8 | |||||||||||||||||||
| Group annuity contract | — | — | 430.1 | 430.1 | |||||||||||||||||||
| Real estate interests | — | — | 0.3 | 0.3 | |||||||||||||||||||
| Total assets at fair value | $ | 33.1 | $ | 72.7 | $ | 430.4 | 536.2 | ||||||||||||||||
Assets measured at net asset value practical expedient (1) | |||||||||||||||||||||||
| Private mutual funds | 47.1 | ||||||||||||||||||||||
| Total plan assets | $ | 583.3 | |||||||||||||||||||||
| Peabody Energy Corporation | ||||||||
| December 31, 2021 | |||||||||||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||
| (Dollars in millions) | |||||||||||||||||||||||
| Corporate bonds | $ | — | $ | 537.5 | $ | — | $ | 537.5 | |||||||||||||||
| U.S. government securities | 125.2 | 22.5 | — | 147.7 | |||||||||||||||||||
| International government securities | — | 15.5 | — | 15.5 | |||||||||||||||||||
| Asset-backed securities | — | 3.3 | — | 3.3 | |||||||||||||||||||
| Cash funds | 30.7 | — | — | 30.7 | |||||||||||||||||||
| Real estate interests | — | — | 0.3 | 0.3 | |||||||||||||||||||
| Total assets at fair value | $ | 155.9 | $ | 578.8 | $ | 0.3 | 735.0 | ||||||||||||||||
Assets measured at net asset value practical expedient (1) | |||||||||||||||||||||||
| Private mutual funds | 37.4 | ||||||||||||||||||||||
| Total plan assets | $ | 772.4 | |||||||||||||||||||||
| December 31, 2018 | |||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | ||||||||||||
| (Dollars in millions) | |||||||||||||||
| Corporate bonds | $ | — | $ | 466.1 | $ | — | $ | 466.1 | |||||||
| U.S. government securities | 181.5 | 17.4 | — | 198.9 | |||||||||||
| International government securities | — | 12.4 | — | 12.4 | |||||||||||
| Commercial paper | — | 2.1 | — | 2.1 | |||||||||||
| Cash funds | 38.4 | — | — | 38.4 | |||||||||||
| Real estate interests | — | — | 6.2 | 6.2 | |||||||||||
| Total assets at fair value | $ | 219.9 | $ | 498.0 | $ | 6.2 | 724.1 | ||||||||
Assets measured at net asset value practical expedient (1) | |||||||||||||||
| Private mutual funds | 40.7 | ||||||||||||||
| Total plan assets | $ | 764.8 | |||||||||||||
The table below sets forth a summary of changes in the fair value of the Master Trust’s Level 3 investments:
| Successor | Predecessor | |||||||||||||
| Year Ended December 31, 2019 | Year Ended December 31, 2018 | April 2 through December 31, 2017 | January 1 through April 1, 2017 | |||||||||||
| (Dollars in millions) | ||||||||||||||
| Balance, beginning of period | $ | 6.2 | $ | 11.8 | $ | 13.8 | $ | 14.1 | ||||||
| Realized (losses) gains | (1.0 | ) | 2.6 | — | 0.6 | |||||||||
| Unrealized gains (losses) relating to investments still held at the reporting date | 1.4 | (2.6 | ) | 2.2 | (0.6 | ) | ||||||||
| Purchases, sales and settlements, net | (2.5 | ) | (5.6 | ) | (4.2 | ) | (0.3 | ) | ||||||
| Balance, end of period | $ | 4.1 | $ | 6.2 | $ | 11.8 | $ | 13.8 | ||||||
| Year Ended December 31, | |||||||||||||||||
| 2022 | 2021 | 2020 | |||||||||||||||
| (Dollars in millions) | |||||||||||||||||
| Balance, beginning of period | $ | 0.3 | $ | 1.2 | $ | 4.1 | |||||||||||
| Realized gains | 0.1 | 0.9 | 1.6 | ||||||||||||||
| Unrealized losses relating to investments still held at the reporting date | (68.8) | (0.6) | (2.1) | ||||||||||||||
| Purchases, sales and settlements, net | 498.8 | (1.2) | (2.4) | ||||||||||||||
| Balance, end of period | $ | 430.4 | $ | 0.3 | $ | 1.2 | |||||||||||
Contributions
Annual contributions to the qualified plans are made in accordance with minimum funding standards and the Company’s agreement with the Pension Benefit Guaranty Corporation. Funding decisions also consider certain funded status thresholds defined by the Pension Protection Act of 2006 (generally 80%). As of December 31, 2019,2022, the Company’s qualified plans are expected to be at or above the Pension Protection Act thresholds. Minimum funding standards are legislated by ERISA and are modified by pension funding stabilization provisions included in the Moving Ahead for Progress in the 21st Century Act of 2012, the Highway and Transportation Funding Act of 2014 and the Bipartisan Budget Act of 2015. Based upon minimum funding requirements, theThe Company iswas not required to make any payments to its qualified pension plans; however, during the year ended December 31, 2019, the Company made aplans in 2022 based on minimum funding requirements and did not make any discretionary contribution of $20.0 million to one of its qualified pension plans.
Estimated Future Benefit Payments
The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid in connection with the Company’s benefit obligation:
| Pension Benefits | |||||
| (Dollars in millions) | |||||
| 2023 | $ | 76.1 | |||
| 2024* | 11.1 | ||||
| 2025* | 11.0 | ||||
| 2026* | 10.8 | ||||
| 2027* | 10.6 | ||||
| Years 2028-2032* | 49.6 | ||||
| Pension Benefits | |||
| (Dollars in millions) | |||
| 2020 | $ | 59.6 | |
| 2021 | 59.3 | ||
| 2022 | 58.8 | ||
| 2023 | 59.5 | ||
| 2024 | 57.1 | ||
| Years 2025-2029 | 268.0 | ||
| Peabody Energy Corporation | 2022 Form 10-K | F-48 | ||||||
Defined Contribution Plans
The Company sponsors employee retirement accounts under 2three 401(k) plans for eligible U.S. employees. The Company matches voluntary contributions to each plan up to specified levels. In May 2020 the Company amended one of its plans to eliminate the formula for calculating matching contributions and provide the Company sole discretion in making any matching contributions. During the period May 2020 to December 2020 the Company suspended matching contributions due to challenging business conditions of COVID-19. In January 2021 the Company reinstated matching contributions. The expense for these plans was $27.8$20.1 million, $30.3 million, $25.5$9.7 million and $5.5$9.6 million for the years ended December 31, 20192022, 2021 and 2018, the period April 2 through December 31, 2017 and the period January 1 through April 1, 2017,2020, respectively. A performanceDiscretionary contribution featurefeatures in one of the plans allowsallow for additional discretionary contributions from the Company. There was 0 performance contributionThe Company granted fordiscretionary contributions of $9.2 million during the year ended December 31, 2019. Prior performance2022. There were no discretionary contributions of $8.9 milliongranted during the years ended December 31, 2021 and $8.5 million2020. Discretionary contributions paid during the year ended December 31, 2022 were $4.0 million. There were no discretionary contributions paid during the years ended December 31, 20192021 and 2018, respectively. There were 0 performance contributions paid during the period April 2 through December 31, 2017 or the period January 1 through April 1, 2017.2020.
Superannuation
The Company makes superannuation contributions for eligible Australia employees in accordance with the employer contribution rate set by the Government of Australia. The expense related to these contributions was $26.5$18.8 million, $31.6 million, $19.9$17.4 million and $6.1$20.5 million for the years ended December 31, 20192022, 2021 and 2018, the period April 2 through December 31, 2017 and the period January 1 through April 1, 2017,2020, respectively. A performance contribution feature allows for additional discretionary contributions from the Company. The Company granted discretionary performance contributions of $1.6 million during the year ended December 31, 2022. There was 0were no discretionary performance contribution granted for the year ended December 31, 2019. Prior performance contributions of approximately $3 million were paid during both of the years ended December 31, 20192021 and 2018.2020. There were 0no discretionary performance contributions paid during the period April 2 throughyears ended December 31, 2017 or the period January 1 through April 1, 2017.2022, 2021 and 2020.
(15) Stockholders’ Equity |
Common Stock
In accordance with the Company’s Fourth Amended and Restated Certificate of Incorporation, the Company has 450.0 million authorized shares of Common Stock, par value $0.01 per share. Holders of Common Stock are entitled to one vote per share on all matters to be voted upon by the stockholders. The holders of Common Stock do not have cumulative voting rights in the election of directors. Holders of Common Stock are entitled to receive ratably dividends if, as and when dividends are declared from time to time by the Board of Directors (the Board) out of funds legally available for that purpose, after payment of dividends required to be paid on any outstanding preferred stock or series common stock. Upon dissolution, liquidation or winding up of the Company, the holders of Common Stock are entitled to receive ratably the assets available for distribution to the stockholders after payment of liabilities and subject to the right of holders of any outstanding preferred stock or series common stock. The Common Stock has no preemptive or conversion rights and is not subject to further calls or assessment by the Company. There are no redemption or sinking fund provisions applicable to the Common Stock.
The following table summarizes Common Stock activity during the periods presented below:
| Year Ended December 31, | |||||||||||||||||
| 2022 | 2021 | 2020 | |||||||||||||||
| (In millions) | |||||||||||||||||
| Shares outstanding at the beginning of the period | 133.3 | 97.8 | 96.9 | ||||||||||||||
| Shares issued for vested restricted stock units | 0.7 | 1.0 | 1.3 | ||||||||||||||
| Shares issued in exchange for debt retirement | — | 10.0 | — | ||||||||||||||
| Shares issued under at-the-market equity offering program | 10.1 | 24.8 | — | ||||||||||||||
| Shares repurchased | (0.2) | (0.3) | (0.4) | ||||||||||||||
| Shares outstanding at the end of the period | 143.9 | 133.3 | 97.8 | ||||||||||||||
| Year Ended December 31, 2019 | Year Ended December 31, 2018 | April 2 through December 31, 2017 | ||||||
| (In millions) | ||||||||
| Shares outstanding at the beginning of the period | 110.4 | 105.2 | 70.9 | |||||
| Shares issued for preferred share conversions | — | 25.5 | 33.8 | |||||
| Shares issued for warrant conversions | — | — | 6.2 | |||||
| Shares issued for vested restricted stock units | 1.5 | 1.1 | 0.1 | |||||
| Shares issued for disputed claims | — | 0.1 | — | |||||
| Shares repurchased | (15.0 | ) | (21.5 | ) | (5.8 | ) | ||
| Shares outstanding at the end of the period | 96.9 | 110.4 | 105.2 | |||||
| Peabody Energy Corporation | 2022 Form 10-K | F-49 | ||||||
Preferred Stock
The Board is authorized to issue up to 100.0 million shares of preferred stock, par value $0.01 per share. On the Effective Date, 50.0 million shares of the preferred stock were designated as Series A Convertible Preferred Stock. On January 31, 2018, the remaining outstanding shares of Series A Convertible Preferred Stock were converted into shares of Common Stock.
| Year Ended December 31, 2018 | April 2 through December 31, 2017 | ||||
| (In millions) | |||||
| Shares outstanding at the beginning of the period | 13.5 | 30.0 | |||
| Shares converted to Common Stock | (13.5 | ) | (17.2 | ) | |
| Shares issued for payable in-kind preferred stock dividends | — | 0.7 | |||
| Shares outstanding at the end of the period | — | 13.5 | |||
Series Common Stock
The Board is authorized to issue up to 50.0 million shares of series common stock, par value $0.01 per share. The Board can determine the terms and rights of each series, whether dividends (if any) will be cumulative or non-cumulative and the dividend rate of the series, redemption or sinking fund provisions, conversion terms, prices and rates and amounts payable on shares of the series in the event of any voluntary or involuntary liquidation, dissolution or winding up of the affairs of the Company and whether the shares of the series will be convertible into shares of any other class or series, or any other security, of the Company or any other corporation. The Board may also determine restrictions on the issuance of shares of the same series or of any other class or series, and the voting rights (if any) of the holders of the series. There were 0no outstanding shares of series common stock as of December 31, 2019.
Treasury Stock
Share repurchases. TheOn August 1, 2017, the Board has authorized a $500.0 million share repurchase program as amended, to allow repurchases of up to $1.5 billion of the outstanding shares of the Company’s common stock and/or preferred stock (Repurchase Program). Repurchases may be made from time, which was eventually expanded to time at the Company’s discretion. The specific timing, price and size of purchases will depend on the share price, general market and economic conditions and other considerations, including compliance with various debt agreements as they may be amended from time to time.$1.5 billion during 2018. The Repurchase Program does not have an expiration date and may be discontinued at any time. Through December 31, 2019,2022, the Company repurchased 41.5 million shares of its Common Stock for $1,340.3 million, (14.6 million shares for $329.9 million during the year ended December 31, 2019; 21.1 million shares for $834.7 million during the year ended December 31, 2018; and 5.8 million shares for $175.7 million during the period April 2 through December 31, 2017), which included commissions paid of $0.8 million. As of December 31, 2019,2022, there was $160.5 million available for repurchase under the Repurchase Program. No additional
Share repurchases are currently planned.
Shares relinquished. 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 number of shares of Common Stock relinquished was 0.2 million, 0.3 million and 0.4 million for both the periodsyears ended December 31, 20192022, 2021 and 2018.2020, respectively. The value of the Common Stock tendered by employees was based upon the closing price on the dates of the respective transactions.
(16) Share-Based Compensation |
The Company has established the Peabody Energy Corporation 2017 Incentive Plan (the 2017 Incentive Plan) for employees, non-employee directors and consultants that allows for the issuance of share-based compensation in various forms including options (including non-qualified stock options and incentive stock options), stock appreciation rights, restricted stock, restricted stock units, deferred stock, performance units, dividend equivalents and cash incentive awards. Under the 2017 Incentive Plan, approximately 14 million shares of the Company’s Common Stock were reserved for issuance. As of December 31, 2019,2022, there are approximately 8.96.9 million shares of the Company’s Common Stock available for grant.
| Peabody Energy Corporation | ||||||||
Share-Based Compensation Expense and Cash Flows
The Company’s share-based compensation expense is recorded in “Operating costs and expenses” and “Selling and administrative expenses” in the consolidated statements of operations. Cash received by the Company upon the exercise of stock options is reflected as a financing activity in the consolidated statements of cash flows. Share-based compensation expense and cash flow amounts were as follows:
| Successor | |||||||||||
| Year Ended December 31, 2019 | Year Ended December 31, 2018 | April 2 through December 31, 2017 | |||||||||
| (Dollars in millions) | |||||||||||
| Share-based compensation expense | $ | 38.3 | $ | 34.9 | $ | 21.8 | |||||
| Tax benefit | — | — | — | ||||||||
| Share-based compensation expense, net of tax benefit | $ | 38.3 | $ | 34.9 | $ | 21.8 | |||||
| Cash received upon the exercise of stock options | — | — | — | ||||||||
| Write-off tax benefits related to share-based compensation | — | — | — | ||||||||
| Year Ended December 31, | |||||||||||||||||
| 2022 | 2021 | 2020 | |||||||||||||||
| (Dollars in millions) | |||||||||||||||||
| Share-based compensation expense | $ | 8.4 | $ | 10.0 | $ | 13.5 | |||||||||||
| Tax benefit | — | — | — | ||||||||||||||
| Share-based compensation expense, net of tax benefit | $ | 8.4 | $ | 10.0 | $ | 13.5 | |||||||||||
| Cash received upon the exercise of stock options | — | — | — | ||||||||||||||
| Write-off tax benefits related to share-based compensation | — | — | — | ||||||||||||||
As of December 31, 2019,2022, the total unrecognized compensation cost related to nonvested awards was $27.7$4.2 million, net of taxes, which is expected to be recognized over 2.5 years with a weighted-average period of 0.60.5 years.
Deferred Stock Units
During the years ended December 31, 20192022, 2021 and 2018 and the period April 2 through December 31, 2017,2020, the Company granted deferred stock units to each of the non-employee members of the Board. The fair value of these units is equal to the market price of the Company’s Common Stock at the date of grant. These deferred stock units generally vest on a monthly basis over 12 months and are settled in Common Stock three years after the date of grant.
Restricted Stock Units
The Company grants restricted stock units to certain senior management and non-senior management employees. For units granted to both senior and non-senior management employees containing only service conditions, the fair value of the award is equal to the market price of the Company’s Common Stock at the date of grant. Units granted to senior and non-senior management employees vest at various times (none of which exceed three years) in accordance with the underlying award agreement. Compensation cost for both senior and non-senior management employees is recognized on a straight-line basis over the requisite service period. The payouts for active grants awarded during the years ended December 31, 20192022, 2021 and 2018 and the period April 2 through December 31, 20172020 will be settled in the Company’s Common Stock.
A summary of restricted stock unit activity is as follows:
| Year Ended December 31, 2019 | Weighted Average Grant-Date Fair Value | |||||
| Nonvested at December 31, 2018 | 2,641,087 | $ | 24.87 | |||
| Granted | 664,899 | 29.75 | ||||
| Vested | (1,401,268 | ) | 23.40 | |||
| Forfeited | (198,693 | ) | 30.96 | |||
| Nonvested at December 31, 2019 | 1,706,025 | $ | 26.89 | |||
| Year Ended December 31, 2022 | Weighted Average Grant-Date Fair Value | ||||||||||
| Nonvested at December 31, 2021 | 1,103,828 | $ | 8.99 | ||||||||
| Granted | 325,040 | 11.87 | |||||||||
| Vested | (550,468) | 10.60 | |||||||||
| Forfeited | (100,087) | 8.38 | |||||||||
| Nonvested at December 31, 2022 | 778,313 | $ | 9.13 | ||||||||
The total fair value at grant date of restricted stock units granted during the years ended December 31, 20192022, 2021 and 2018 and the period April 2 through December 31, 20172020 was $19.8$3.9 million, $18.2$3.1 million and $79.8$16.6 million, respectively.
| Peabody Energy Corporation | 2022 Form 10-K | F-51 | ||||||
The restricted stock units receive dividend equivalent units (DEUs) upon payment of cash dividends to holders of Common Stock. DEUs vest subject to the same vesting requirements as the underlying restricted stock unit award. As of December 31, 2019,2022, there were approximately 176,000no nonvested DEUs. The total fair value of restricted stock units and DEUs vested was $40.3$6.8 million, $46.2$3.3 million and $0.9$5.6 million during the years ended December 31, 20192022, 2021 and 2018 and2020, respectively.
In March 2021 the period April 2 throughCompany entered into a transition agreement with its former chief executive officer which resulted in a modification to restricted stock units granted. Under terms of the agreement, any restricted stock units held by the former chief executive officer that would have vested under their original terms during the twelve months following the specified termination vested upon such date. As a result of this modification, the Company avoided additional compensation expense of approximately $1.3 million for the year ended December 31, 2017, respectively.2021.
Performance Units
Performance units are typically granted annually in January and vest over a three-year measurement period and are primarily limited to senior management personnel. The performance units are usually subject to the achievement of goals based on the following conditions: three-year return on invested capital and environmental reclamation (performance condition). In addition, the payout of the performance units can be increased or decreased by up to 25% of the award based on three-year stock price performance compared to a custom peer group (market condition). The performance units can be increased by up to a maximum of 100% of the award granted. There were 0no performance units granted during the period April 2 through December 31, 2017. Awards granted during the years ended December 31, 2019 and 20182022 or 2021. Awards granted during the year ended December 31, 2020 will be settled in the Company's Common Stock.
A summary of performance unit activity is as follows:
| Year Ended December 31, 2019 | Weighted Average Remaining Contractual Life | ||||
| Nonvested at December 31, 2018 | 206,630 | 2.0 | |||
| Granted | 264,918 | ||||
| Vested | — | ||||
| Forfeited | (44,942 | ) | |||
| Nonvested at December 31, 2019 | 426,606 | 1.6 | |||
| Year Ended December 31, 2022 | Weighted Average Remaining Contractual Life | ||||||||||
| Nonvested at December 31, 2021 | 650,906 | 0.7 | |||||||||
| Granted | — | ||||||||||
| Vested | (109,709) | ||||||||||
| Forfeited | (91,176) | ||||||||||
| Nonvested at December 31, 2022 | 450,021 | — | |||||||||
As of December 31, 2019, 02022, there were 120,289 performance units and DEU’s vested that had vested.an aggregate intrinsic value of $2.1 million and a conversion price per share of $17.43.
The performance units receive DEUs upon payment of cash dividends to holders of Common Stock. DEUs vest subject to the same vesting requirements as the underlying performance unit award. As of December 31, 2019,2022, there were approximately 44,000no nonvested DEUsDEUs.
| Year Ended December 31, | |||||
| 2019 | 2018 | ||||
| Risk-free interest rate | 2.44 | % | 2.24 | % | |
| Expected volatility | 48.81 | % | 57.75 | % | |
| Dividend yield | — | % | — | % | |
| Predecessor | |||
| January 1 through April 1, 2017 | |||
| (Dollars in millions) | |||
| Share-based compensation expense - equity classified awards | $ | 1.9 | |
| Tax benefit | — | ||
| Share-based compensation expense, net of tax benefit | $ | 1.9 | |
| Cash received upon the exercise of stock options and from employee stock purchases | — | ||
| Write-off tax benefits related to share-based compensation | — | ||
Foreign Currency Translation Adjustment | Net Actuarial Loss Associated with Postretirement Plans and Workers’ Compensation Obligations | Prior Service Credit (Cost) Associated with Postretirement Plans | Cash Flow Hedges | Total Accumulated Other Comprehensive (Loss) Income | |||||||||||||||
| (Dollars in millions) | |||||||||||||||||||
| Predecessor Company | |||||||||||||||||||
| December 31, 2016 | $ | (148.2 | ) | $ | (256.3 | ) | $ | 21.7 | $ | (94.2 | ) | $ | (477.0 | ) | |||||
| Reclassification from other comprehensive income to earnings | — | 5.8 | (1.4 | ) | 18.6 | 23.0 | |||||||||||||
| Current period change | 5.5 | — | — | — | 5.5 | ||||||||||||||
| Fresh start reporting adjustment | 142.7 | 250.5 | (20.3 | ) | 75.6 | 448.5 | |||||||||||||
| April 1, 2017 | $ | — | $ | — | $ | — | $ | — | $ | — | |||||||||
| Successor Company | |||||||||||||||||||
| Current period change | 1.4 | — | — | — | 1.4 | ||||||||||||||
| December 31, 2017 | 1.4 | — | — | — | 1.4 | ||||||||||||||
| Current period change | (5.9 | ) | — | 44.6 | — | 38.7 | |||||||||||||
| December 31, 2018 | (4.5 | ) | — | 44.6 | — | 40.1 | |||||||||||||
| Reclassification from other comprehensive income to earnings | — | — | (8.7 | ) | — | (8.7 | ) | ||||||||||||
| Current period change | 0.2 | — | — | — | 0.2 | ||||||||||||||
| December 31, 2019 | $ | (4.3 | ) | $ | — | $ | 35.9 | $ | — | $ | 31.6 | ||||||||
Amount reclassified from accumulated other comprehensive loss (1) | |||||||||
| Successor | Predecessor | ||||||||
| Details about accumulated other comprehensive loss components | Year Ended December 31, 2019 | January 1 through April 1, 2017 | Affected line item in the consolidated statement of operations | ||||||
| (Dollars in millions) | |||||||||
| Net actuarial loss associated with postretirement plans and workers’ compensation obligations: | |||||||||
| Postretirement health care and life insurance benefits | $ | — | $ | (5.5 | ) | Net periodic benefit costs, excluding service cost | |||
| Defined benefit pension plans | — | (6.3 | ) | Net periodic benefit costs, excluding service cost | |||||
| Workers’ compensation amortization | — | 2.7 | Net periodic benefit costs, excluding service cost | ||||||
| — | (9.1 | ) | Total before income taxes | ||||||
| — | 3.3 | Income tax benefit | |||||||
| $ | — | $ | (5.8 | ) | Total after income taxes | ||||
| Prior service credit (cost) associated with postretirement plans: | |||||||||
| Postretirement health care and life insurance benefits | $ | 8.7 | $ | 2.3 | Net periodic benefit costs, excluding service cost | ||||
| Defined benefit pension plans | — | (0.1 | ) | Net periodic benefit costs, excluding service cost | |||||
| 8.7 | 2.2 | Total before income taxes | |||||||
| — | (0.8 | ) | Income tax provision | ||||||
| $ | 8.7 | $ | 1.4 | Total after income taxes | |||||
| Cash flow hedges: | |||||||||
| Foreign currency cash flow hedge contracts | $ | — | $ | (16.6 | ) | Operating costs and expenses | |||
| Fuel and explosives commodity swaps | — | (11.0 | ) | Operating costs and expenses | |||||
| Insignificant items | — | (0.1 | ) | ||||||
| — | (27.7 | ) | Total before income taxes | ||||||
| — | 9.1 | Income tax benefit | |||||||
| $ | — | $ | (18.6 | ) | Total after income taxes | ||||
Divestitures and Other Transactions
During July 2021, the Company executed transactions to sell its closed Millennium and Wilkie Creek Mines, which reduced its closed mine reclamation liabilities and associated costs. The Company’s KayentaMillennium Mine closed during August 2019 upon termination of its coal supply agreement withwas sold for minimal cash consideration and the Navajo Generating Station (NGS) in Arizona. The NGS was the sole customerassumption of the Kayenta Mine andmajority of the coal supply agreement provided for consideration tomine’s reclamation liabilities. At December 31, 2022, the Company related to its post-mining obligationsremains responsible for retiree healthcare and reclamation costs. A cumulative portion of such consideration, $53.5 million, was held in trust and released to the Company upon termination. During the fourth quarter of 2019, the parties entered into a settlement agreement to finalize such consideration for an additional $78.5 million payable to the Company. Of this amount, $35.4 million was receivable at December 31, 2019 and $16.3$5.7 million of such receivable was collected in January 2020.
| Peabody Energy Corporation | 2022 Form 10-K | F-52 | ||||||
The Wilkie Creek Mine was sold for minimal cash consideration and full assumption of the mine’s reclamation liabilities. The Company sold its 50% interest in the Red Mountain Joint Venture (RMJV) with BHP Billiton Mitsui Coal Pty Ltd (BMC) for $20.0 million and recorded a gain of $7.1$24.6 million in connection with the sale, which is included within “Net gain on disposals”“Income (loss) from discontinued operations, net of income taxes” in the accompanying consolidated statements of operations for the year ended December 31, 2018. RMJV operated2021.
United Wambo Joint Venture with Glencore
In December 2019 the coal handling and preparation plant utilized byCompany formed an unincorporated joint venture with Glencore plc (Glencore), in which the Company holds a 50% interest, to combine the existing operations of the Company’s MillenniumWambo Open-Cut Mine in Australia with the adjacent coal reserves of Glencore’s United Mine. BMC assumedThe Company proportionally consolidates the reclamation obligationsentity based upon its economic interest.
Both parties contributed mining tenements upon formation of the joint venture (United Wambo Joint Venture), and combined operations commenced in December 2020. At that date, the parties contributed mining equipment and other commitments associated withassets, and certain additional construction and development activities are ongoing. During the assets of RMJV. The Millennium Mine had continued usage of the coal handlingyears ended December 31, 2022, 2021 and preparation plant and the associated rail loading facility until the end of 2019 via a coal washing take-or-pay agreement with BMC.
(18) Earnings per Share (EPS)
Basic EPS is computed based on the weighted average number of shares of common stock outstanding during the period. Diluted EPS is computed based on the weighted average number of shares of common stock plus the effect of dilutive potential common shares outstanding. As such, the Company includes the 2028 Convertible Notes and share-based compensation awards in its potentially dilutive securities. DilutiveGenerally, dilutive securities are not included in the computation of loss per share when a company reports a net loss from continuing operations as the impact would be anti-dilutive.
For all but the performance units, the potentially dilutive impact of the Company’s share-based compensation awards is determined using the treasury stock method. Under the treasury stock method, awards are treated as if they had been exercised with any proceeds used to repurchase common stock at the average market price during the period. Any incremental difference between the assumed number of shares issued and purchased is included in the diluted share computation. For the performance units, their contingent features result in an assessment for any potentially dilutive common stock by using the end of the reporting period as if it were the end of the contingency period for all units granted. For further discussion of the Company’s share-based compensation awards, see Note 20.16. “Share-Based Compensation.”
The computation of diluted EPS excluded aggregate share-based compensation awards of less than 0.1 million for both the years ended December 31, 2022 and 2021, and approximately 1.9 million and 0.32.2 million for the year ended December 31, 2019 and the period January 1 through April 1, 2017, respectively, and less than 0.1 million for both the year ended December 31, 2018 and the period April 2 through December 31, 2017,2020, because to do so would have been anti-dilutive for those periods. Because the potential dilutive impact of such share-based compensation awards is calculated under the treasury stock method, anti-dilution generally occurs when the exercise prices or unrecognized compensation cost per share of such awards are higher than the Company’s average stock price during the applicable period. Anti-dilution also occurs when a company reports a net loss from continuing operations, and the dilutive impact of all share-based compensation awards are excluded accordingly.
| Peabody Energy Corporation | ||||||||
The following illustrates the earnings allocation method utilized in the calculation of basic and diluted EPS:
| Year Ended December 31, | |||||||||||||||||
| 2022 | 2021 | 2020 | |||||||||||||||
| (In millions, except per share data) | |||||||||||||||||
| Basic EPS numerator: | |||||||||||||||||
| Income (loss) from continuing operations, net of income taxes | $ | 1,317.4 | $ | 347.4 | $ | (1,859.8) | |||||||||||
| Less: Net income (loss) attributable to noncontrolling interests | 22.0 | 11.3 | (3.5) | ||||||||||||||
| Income (loss) from continuing operations attributable to common stockholders | 1,295.4 | 336.1 | (1,856.3) | ||||||||||||||
| Income (loss) from discontinued operations, net of income taxes | 1.7 | 24.0 | (14.0) | ||||||||||||||
| Net income (loss) attributable to common stockholders | $ | 1,297.1 | $ | 360.1 | $ | (1,870.3) | |||||||||||
| Diluted EPS numerator: | |||||||||||||||||
| Income (loss) from continuing operations, net of income taxes | $ | 1,317.4 | $ | 347.4 | $ | (1,859.8) | |||||||||||
| Add: Tax adjusted interest expense related to 2028 Convertible Notes | 8.7 | — | — | ||||||||||||||
| Less: Net income (loss) attributable to noncontrolling interests | 22.0 | 11.3 | (3.5) | ||||||||||||||
| Income (loss) from continuing operations attributable to common stockholders | 1,304.1 | 336.1 | (1,856.3) | ||||||||||||||
| Income (loss) from discontinued operations, net of income taxes | 1.7 | 24.0 | (14.0) | ||||||||||||||
| Net income (loss) attributable to common stockholders | $ | 1,305.8 | $ | 360.1 | $ | (1,870.3) | |||||||||||
| EPS denominator: | |||||||||||||||||
| Weighted average shares outstanding — basic | 142.1 | 111.1 | 97.7 | ||||||||||||||
| Dilutive impact of share-based compensation awards | 1.6 | 0.9 | — | ||||||||||||||
| Dilutive impact of 2028 Convertible Notes | 13.5 | — | — | ||||||||||||||
| Weighted average shares outstanding — diluted | 157.2 | 112.0 | 97.7 | ||||||||||||||
| Basic EPS attributable to common stockholders: | |||||||||||||||||
| Income (loss) from continuing operations | $ | 9.12 | $ | 3.03 | $ | (18.99) | |||||||||||
| Income (loss) from discontinued operations | 0.01 | 0.21 | (0.15) | ||||||||||||||
| Net income (loss) attributable to common stockholders | $ | 9.13 | $ | 3.24 | $ | (19.14) | |||||||||||
| Diluted EPS attributable to common stockholders: | |||||||||||||||||
| Income (loss) from continuing operations | $ | 8.29 | $ | 3.00 | $ | (18.99) | |||||||||||
| Income (loss) from discontinued operations | 0.02 | 0.22 | (0.15) | ||||||||||||||
| Net income (loss) attributable to common stockholders | $ | 8.31 | $ | 3.22 | $ | (19.14) | |||||||||||
| Successor | Predecessor | |||||||||||||
| Year Ended December 31, 2019 | Year Ended December 31, 2018 | April 2 through December 31, 2017 | January 1 through April 1, 2017 | |||||||||||
| (In millions, except per share amounts) | ||||||||||||||
| EPS numerator: | ||||||||||||||
| (Loss) income from continuing operations, net of income taxes | $ | (188.3 | ) | $ | 645.7 | $ | 713.1 | $ | (195.5 | ) | ||||
| Less: Series A Convertible Preferred Stock dividends | — | 102.5 | 179.5 | — | ||||||||||
| Less: Net income attributable to noncontrolling interests | 26.2 | 16.9 | 15.2 | 4.8 | ||||||||||
| (Loss) income from continuing operations attributable to common stockholders, before allocation of earnings to participating securities | (214.5 | ) | 526.3 | 518.4 | (200.3 | ) | ||||||||
| Less: Earnings allocated to participating securities | — | 7.9 | 129.0 | — | ||||||||||
(Loss) income from continuing operations attributable to common stockholders, after allocation of earnings to participating securities (1) | (214.5 | ) | 518.4 | 389.4 | (200.3 | ) | ||||||||
| Income (loss) from discontinued operations, net of income taxes | 3.2 | 18.1 | (19.8 | ) | (16.2 | ) | ||||||||
| Less: Income (loss) from discontinued operations allocated to participating securities | — | 0.3 | (4.9 | ) | — | |||||||||
| Income (loss) from discontinued operations attributable to common stockholders, after allocation of earnings to participating securities | 3.2 | 17.8 | (14.9 | ) | (16.2 | ) | ||||||||
Net (loss) income attributable to common stockholders, after allocation of earnings to participating securities (1) | $ | (211.3 | ) | $ | 536.2 | $ | 374.5 | $ | (216.5 | ) | ||||
| EPS denominator: | ||||||||||||||
| Weighted average shares outstanding — basic | 103.7 | 119.3 | 101.1 | 18.3 | ||||||||||
| Impact of dilutive securities | — | 1.7 | 1.4 | — | ||||||||||
Weighted average shares outstanding — diluted (2) | 103.7 | 121.0 | 102.5 | 18.3 | ||||||||||
| Basic EPS attributable to common stockholders: | ||||||||||||||
| (Loss) income from continuing operations | $ | (2.07 | ) | $ | 4.35 | $ | 3.85 | $ | (10.93 | ) | ||||
| Income (loss) from discontinued operations | 0.03 | 0.15 | (0.15 | ) | (0.88 | ) | ||||||||
| Net (loss) income attributable to common stockholders | $ | (2.04 | ) | $ | 4.50 | $ | 3.70 | $ | (11.81 | ) | ||||
| Diluted EPS attributable to common stockholders: | ||||||||||||||
| (Loss) income from continuing operations | $ | (2.07 | ) | $ | 4.28 | $ | 3.81 | $ | (10.93 | ) | ||||
| Income (loss) from discontinued operations | 0.03 | 0.15 | (0.14 | ) | (0.88 | ) | ||||||||
| Net (loss) income attributable to common stockholders | $ | (2.04 | ) | $ | 4.43 | $ | 3.67 | $ | (11.81 | ) | ||||
On December 31, 2019,2022, the Company had approximately 6,6005,500 employees worldwide, including approximately 5,0004,300 hourly employees; the employee amounts exclude employees that were employed at operations classified as discontinued operations. Approximately 42%34% of those hourly employees were represented by organized labor unions and were employed by mines that generated 19%16% of the Company’s 20192022 coal production from continuing operations. In the U.S., 2 minesthe hourly employees of one active mine and one inactive mine are represented by an organized labor union. In Australia, the coal mining industry is unionized and the majority of hourly workers employed at the Company’s Australian mining operations are members of trade unions. The Construction, Forestry, Maritime, Mining and Energy Union (CFMMEU) generally represents the Company’s Australian subsidiaries’ hourly production and engineering employees, including those employed through contract mining relationships. The Company believes labor relations with its employees are good. Should that condition change, the Company could experience labor disputes, work stoppages or other disruptions in production that could negatively impact the Company’s results of operations and cash flows.
| Peabody Energy Corporation | ||||||||
| Approximate Number of | Union | Current Agreement Expiration Date or Date Amendable | ||||||||||||||||||
| Kayenta | 20 | UMWA | November 2024 | |||||||||||||||||
| Shoal Creek | 330 | UMWA | December 2024 | |||||||||||||||||
| Australia | ||||||||||||||||||||
| Wilpinjong | 465 | CFMMEU | June 2024 | |||||||||||||||||
| Coppabella | 330 | CFMMEU | February 2026 | |||||||||||||||||
| 225 | N/A | June 2023 | ||||||||||||||||||
| Metropolitan | ||||||||||||||||||||
| Underground employees | 150 | CFMMEU | May 2025 | |||||||||||||||||
Handling and preparation plant | 20 | CFMMEU | May |
| Wambo Underground | ||||||||||||||||||||
| Handling and preparation plant | 20 | CFMMEU | August 2025 |
(1) Employees of the Moorvale Mine operate on individual contracts under a direct engagement model. Such contracts are modeled after the Company’s former labor agreement with CFMMEU which ended in 2017. According to a memorandum of understanding between the Company and employees, individual contracts may be renegotiated in June 2023. (2) The Company, employees and the CFMMEU are currently negotiating a new labor agreement. (20) Financial Instruments, Guarantees With Off-Balance-Sheet Risk and Other Guarantees |
In the normal course of business, the Company is a party to various guarantees and financial instruments that carry off-balance-sheet risk and are not reflected in the accompanying consolidated balance sheets. At December 31, 2019,2022, such instruments included $1,609.2$1,376.8 million of surety bonds and bank guarantees and $200.5$569.6 million of letters of credit. Such financial instruments provide support for the Company’s reclamation bonding requirements, lease obligations, insurance policies and various other performance guarantees. The Company periodically evaluates the instruments for on-balance-sheet treatment based on the amount of exposure under the instrument and the likelihood of required performance. The Company does not expect any material losses to result from these guarantees or off-balance-sheet instruments in excess of liabilities provided for in the accompanying consolidated balance sheets.
In November 2020, the Company entered into an agreement with the providers of its surety bond portfolio to resolve previous collateral demands. In accordance with the agreement, the Company initially provided $75.0 million of collateral, in the form of letters of credit. Upon completion of the 2021 debt restructuring transactions described in Note 10. “Long-term Debt”, other provisions of the agreement became effective. In particular, the Company granted second liens on $200.0 million of certain mining equipment and is further required to post an additional $25.0 million of collateral per year from 2021 through 2024 for the benefit of the surety providers. The collateral postings further increase to the extent the Company generates more than $100.0 million of free cash flow (as defined in the surety agreement) in any twelve-month period or has cumulative asset sales in excess of $10.0 million, as of the last quarter end during the term of the agreement. Based upon the Company’s free cash flow since entering into the surety agreement, additional collateral of $102.4 million was posted during the year ended December 31, 2022 and $74.4 million was posted in January 2023, in the form of cash-collateralized letters of credit.
Under the agreement, the relevant surety providers agreed to a standstill through December 31, 2025, during which time, the surety providers will not demand collateral incremental to that described above, draw on letters of credit posted for the benefit of themselves or cancel any existing surety bond. The Company will not pay dividends or make share repurchases during the standstill period, unless otherwise agreed between parties.
| Peabody Energy Corporation | 2022 Form 10-K | F-55 | ||||||
Reclamation Bonding
The Company is required to provide various forms of financial assurance in support of its mining reclamation obligations in the jurisdictions in which it operates. Such requirements are typically established by statute or under mining permits. Historically, such assurances have taken the form of third-party instruments such as surety bonds, bank guarantees, letters of credit, cash collateral held in restricted accounts, and self-bonding arrangements in the U.S. In connection with its emergence from the Chapter 11 Cases, the Company elected to utilize primarily a portfolio of surety bonds to support its U.S. obligations.
At December 31, 2019,2022, the Company’s asset retirement obligations of $752.3$750.0 million were supported by surety bonds of $1,401.7$1,250.1 million, as well as letters of credit issued under the Company’s receivables securitization program and Revolver amountingRevolver. Letters of credit issued at December 31, 2022, which served as collateral for surety bonds in support of asset retirement obligations, amounted to $106.1$431.7 million.
Accounts Receivable Securitization
The Company entered into the Sixth Amended and Restated Receivables Purchase Agreement, as amended, dated as of April 3, 2017 (the Receivables Purchase Agreement) to extend the Company’s receivables securitization facility previously in place and expand that facility to include certain receivables from the Company’s Australian operations. The receivables securitization program (Securitization Program) is subject to customary events of default set forth in the Receivables Purchase Agreement. The Receivables Purchase Agreement was amended in January 2022 to extend the Securitization Program provides for up to January 2025 and reduce the available funding capacity from $250.0 million into $175.0 million. Such funding is accounted for as a secured borrowing, limited to the availability of eligible receivables, and may be secured by a combination of collateral and the trade receivables underlying the program, from time to time. Funding capacity under the Securitization Program may also be utilized for letters of credit in support of other obligations. During 2019, the Company entered into an amendment toBorrowings under the Securitization Program to extend its term through April 1, 2022bear interest at BSBY plus 2.1% per annum and reduce program fees.
At December 31, 2019,2022, the Company had 0no outstanding borrowings and $132.7$168.0 million of letters of credit drawnissued under the Securitization Program. The letters of credit were primarily in support of portions of the Company’s obligations for reclamation workers’ compensation and postretirement benefits.obligations. Availability under the Securitization Program, which is adjusted for certain ineligible receivables, was $45.0$7.0 million at December 31, 2019.2022. The Company had 0was not required to post cash collateral requirement under the Securitization Program at either December 31, 20192022 or 2018. 2021.
The Company incurred interest and fees associated with the Securitization Program of $5.5$3.8 million, $5.2$2.9 million and $5.3$2.6 million during the years ended December 31, 20192022, 2021 and 2018 and the period April 2 through December 31, 2017,2020, respectively, which have been recorded as “Interest expense” in the accompanying statements of operations. As it relates to the former receivables securitization facility in place prior to the Effective Date,
Collateralized Letter of Credit Agreement
In February 2022, the Company incurred interest expenseentered into a new agreement, which provides up to $250.0 million of $2.0capacity for irrevocable standby letters of credit, expected to primarily support reclamation bonding requirements. The agreement requires the Company to provide cash collateral at a level of 103% of the aggregate amount of letters of credit outstanding under the arrangement (limited to $5.0 million duringtotal excess collateralization.) Outstanding letters of credit bear a fixed fee in the period January 1 through April 1, 2017.
amount of 0.75% per annum. The Company remitsreceives a variable deposit rate on the amount of cash to certain regulatory authorities and other third parties as collateral for financial assurances associated with a varietyposted in support of long-term obligations and commitments surroundingletters of credit. The agreement has an initial expiration date of December 31, 2025. At December 31, 2022, letters of credit of $103.3 million were outstanding under the mining, reclamation and shippingagreement, which were collateralized by cash of its production. The$111.0 million, which includes interest earned on deposits.
Cash Collateral Arrangements
As of December 31, 2022, the Company had $323.1other collateral balances of $77.0 million held by third partiesposted, including $43.9 million related to such obligationsreclamation, which are included with “Restricted cash and collateral arrangements” in the accompanying consolidated balance sheets. Such collateral balances amounted to $23.8 million at December 31, 2017. All such collateral was returned2021, including $15.0 million related to the Company during the year ended December 31, 2018, largely as the resultreclamation.
| Peabody Energy Corporation | 2022 Form 10-K | F-56 | ||||||
PEABODY ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Other
The Company is the lessee under numerous equipment and property leases. It is common in such commercial lease transactions for the Company, as the lessee, to agree to indemnify the lessor for the value of the property or equipment leased, should the property be damaged or lost during the course of the Company’s operations. The Company expects that losses with respect to leased property, if any, may be covered by insurance (subject to deductibles). The Company and certain of its subsidiaries have guaranteed other subsidiaries’ performance under various lease obligations. Aside from indemnification of the lessor for the value of the property leased, the Company’s maximum potential obligations under its leases are equal to the respective future minimum lease payments, and the Company assumes that no amounts could be recovered from third parties. In this regard, the Company recorded provisions of $0.3 million and $50.4 million during the years ended December 31, 2019 and 2018, respectively, for the loss of leased equipment at the North Goonyella Mine as described in Note 22. “Other Events.”
(21) Commitments and Contingencies |
Commitments
Unconditional Purchase Obligations
As of December 31, 2019,2022, purchase commitments for capital expenditures were $39.7$102.1 million, all of which is obligated inwithin the next year.three years, with $94.1 million obligated within the next 12 months.
In Australia, the Company has generally secured the ability to transport coal through rail contracts and ownership interests in five east coast coal export terminals that are primarily funded through take-or-pay arrangements with terms ranging up to 2320 years. In the U.S., the Company has entered into certain long-term coal export terminal agreements to secure export capacity through the Gulf Coast. As of December 31, 2019,2022, these Australian and U.S. commitments under take-or-pay arrangements totaled $1.1$1.4 billion, of which approximately $116$103 million is obligated within the next year.
Contingencies
From time to time, the Company or its subsidiaries are involved in legal proceedings arising in the ordinary course of business or related to indemnities or historical operations. The Company believes it has recorded adequate reserves for these liabilities. The Company discusses its significant legal proceedings below, including ongoing proceedings and those that impacted the Company’s results of operations for the periods presented.
Litigation Relating to the Chapter 11 Cases
On August 2, 2022, Peabody and Plaintiffs agreed to settle all claims brought on behalf of all persons who purchased or otherwise acquired the Company’s shares between April 3, 2017 and October 28, 2019 in exchange for $4.6 million, to be paid by Peabody’s insurers. The parties further negotiated a definitive stipulation of settlement and related documents which do not contain any admission of liability, wrongdoing or responsibility by any of the parties filed a dismissal ofand provide that the litigation on January 24, 2020.
| Peabody Energy Corporation | ||||||||
On February 10, 2021, a second plaintiff (Di Fusco), putatively on behalf of the Company, filed a similar shareholder derivative lawsuit, styled Di Fusco v. Glenn Kellow, et al., Case No. 1:21-cv-00183-UNA (D. Del. filed Feb. 10, 2021), in the U.S. District Court for the District of Delaware against the directors and current and former officers of the Company, as defendants. The Company was named as a defendant, along with numerous other companies,nominal defendant. This suit makes claims similar to those made in three nearly identical lawsuits brought by municipalitiesthe Phelps matter, but asserts a claim for alleged misstatements in California on July 17, 2017. The lawsuits seek to hold a wide variety of companies that produce fossil fuels liable for the alleged impactsproxy statement under Section 14(a) of the greenhouse gas emissions attributable to those fuelsSecurities and seek compensatory and punitive damages in an amount to be proven at trial, attorneys’ fees and costs, disgorgementExchange Act of profits and equitable relief of abatement.The lawsuits primarily assert that1934. In late March 2021, the companies’ products have caused a sea level rise that is damaging the plaintiffs. The complaints specifically alleged that the defendants’ activities from 1965 to 2015 caused such damage. The Companyparties filed a motionstipulation agreeing to enforceconsolidate and stay both derivative actions for judicial efficiency and cost until the Plan because it enjoins claims that arose beforeCourt ruled on the effective date of the Plan. The motion to enforce was granted on October 24, 2017, and the Bankruptcy Court ordered the plaintiffs to dismiss their lawsuits against the Company. On November 26, 2017, the plaintiffs appealed the Bankruptcy Court’s October 24, 2017 order to the District Court. On November 28, 2017, the plaintiffs sought a stay pending appeal from the Bankruptcy Court, which was denied on December 8, 2017. On December 19, 2017, the plaintiffs moved the District Court for a stay pending appeal. The District Court denied the stay request on September 20, 2018, and the plaintiffs have appealed that decision to the Eighth Circuit. On March 29, 2019, the District Court affirmed the Bankruptcy Court ruling enjoining the plaintiffs from proceeding with their lawsuits against the Company. That ruling likewise is being appealed. In the underlying cases pending in California, the U.S. District Court for the Northern District of California granted plaintiffs’ motion for remand and decided the cases should be heard in state court. The defendants appealed the order granting remand to the Ninth Circuit and sought a stay of the U.S. District Court for the Northern District of California decision pending completion of the Ninth Circuit appeal. The U.S. District Court for the Northern District of California granted defendants’ request for a stay pending completion of the Ninth Circuit appeal. The plaintiffs filed a motion to dismiss partin the Securities Class Action.
In light of the appeal. The parties are now litigatingsettlement agreement in the Securities Class Action, on September 7, 2022, the Court entered Stipulation and Order of Voluntary Dismissal Without Prejudice Pursuant to Fed. R. Civ. P. 419a)(1)(A)(ii) for the Phelps and Di Fusco matters; effectively closing the shareholder derivative lawsuits.
Metropolitan Mine Stormwater Discharge. Over the past two years, there has been significantly high rainfall in New South Wales, including unprecedented rain totals at the Ninth Circuit whetherMetropolitan Mine site. While stormwater collected at the mine site is managed through two sedimentation dams, at times the heavy rainfall has presented challenges with managing the significant volumes of stormwater, as the surface water management infrastructure has not had sufficient capacity. As a result, on multiple occasions throughout 2021 and 2022 stormwater has been discharged from the mine site. Metropolitan Collieries Pty Ltd (MCPL), a wholly-owned subsidiary of PEC, removed accumulated material from the sedimentation dams to restore full site stormwater capacity by December 31, 2022 and has identified and is implementing additional controls for the management of sediment moving forward. Despite the measures undertaken by MCPL to manage and improve the situation, the Environment Protection Authority is currently undertaking an investigation in relation to the discharges of sediment laden water from the mine site and a review process of the Metropolitan Mine’s environmental protection license. The Environment Protection Authority is investigating potential offenses against the environmental protection legislation arising from the discharges.
Puerto Rico Climate Change Lawsuit. On November 22, 2022, the Municipalities of Puerto Rico filed a class action complaint for damages against several major energy fuel producers, including Peabody Energy. This lawsuit represents the latest in a series of lawsuits that have been brought in both state orand federal court should heararound the United States, generally seeking to impose liability on the energy fuel producers for the effects allegedly caused by climate change. Many of these lawsuits. Regardlesslawsuits have been brought on behalf of whether state court or federal court isgovernmental entities (counties, cities, and towns) by plaintiff law firms on a contingent fee arrangement. The causes of action in the venue,Puerto Rico lawsuit include public and private nuisance, liability for failure to warn, consumer fraud, antitrust and claims under the Racketeer Influenced and Corrupt Organizations Act. As of February 17, 2023, the Company believeshas not been properly served with a complaint in the lawsuits against it should be dismissed under enforcementmatter styled: The Municipalities of the Plan. The Company does not believe the lawsuits are meritorious and, if the lawsuits are not dismissed, the Company intends to vigorously defend them.Puerto Rico v. Exxon Mobil et al., Case No. 3:22-cv-01550 (USDC D.P.R.).
Other
At times, the Company becomes a party to other disputes, including those related to contract miner performance, claims, lawsuits, arbitration proceedings, regulatory investigations and administrative procedures in the ordinary course of business in the U.S., Australia and other countries where the Company does business. Based on current information, the Company believes that such other pending or threatened proceedings are likely to be resolved without a material adverse effect on its financial condition, results of operations or cash flows.
| Successor | |||||||||||||||
| Year Ended December 31, 2019 | |||||||||||||||
| First Quarter | Second Quarter | Third Quarter | Fourth Quarter | ||||||||||||
| (In millions, except per share data) | |||||||||||||||
| Revenues | $ | 1,250.6 | $ | 1,149.0 | $ | 1,106.4 | $ | 1,117.4 | |||||||
| Operating profit (loss) | 184.5 | 79.5 | (36.8 | ) | (165.5 | ) | |||||||||
| Income (loss) from continuing operations, net of income taxes | 133.3 | 42.9 | (74.3 | ) | (290.2 | ) | |||||||||
| Net income (loss) | 129.9 | 39.5 | (78.1 | ) | (276.4 | ) | |||||||||
| Net income (loss) attributable to common stockholders | 124.2 | 37.1 | (82.8 | ) | (289.8 | ) | |||||||||
Basic EPS — continuing operations (1) | $ | 1.18 | $ | 0.38 | $ | (0.77 | ) | $ | (3.12 | ) | |||||
Diluted EPS — continuing operations (1) | $ | 1.15 | $ | 0.37 | $ | (0.77 | ) | $ | (3.12 | ) | |||||
| Weighted average shares used in calculating basic EPS | 108.5 | 107.0 | 102.2 | 97.3 | |||||||||||
| Weighted average shares used in calculating diluted EPS | 110.5 | 108.1 | 102.2 | 97.3 | |||||||||||
| Peabody Energy Corporation | ||||||||
| Successor | |||||||||||||||
| Year Ended December 31, 2018 | |||||||||||||||
| First Quarter | Second Quarter | Third Quarter | Fourth Quarter | ||||||||||||
| (In millions, except per share data) | |||||||||||||||
| Revenues | $ | 1,462.7 | $ | 1,309.4 | $ | 1,412.6 | $ | 1,397.1 | |||||||
| Operating profit | 239.2 | 165.3 | 130.3 | 126.8 | |||||||||||
| Income from continuing operations, net of income taxes | 208.3 | 120.0 | 83.9 | 233.5 | |||||||||||
| Net income | 207.0 | 116.4 | 79.8 | 260.6 | |||||||||||
| Net income attributable to common stockholders | 106.6 | 113.7 | 71.5 | 252.6 | |||||||||||
Basic EPS — continuing operations (1) | $ | 0.84 | $ | 0.94 | $ | 0.64 | $ | 1.99 | |||||||
Diluted EPS — continuing operations (1) | $ | 0.83 | $ | 0.93 | $ | 0.63 | $ | 1.97 | |||||||
| Weighted average shares used in calculating basic EPS | 120.9 | 124.5 | 118.6 | 113.1 | |||||||||||
| Weighted average shares used in calculating diluted EPS | 123.2 | 126.0 | 120.3 | 114.7 | |||||||||||
Patriot had federal and state black lung occupational disease liabilities related to workers employed in Queensland’s Bowen Basinperiods prior to Patriot’s spin-off from the Company in 2007. Upon spin-off, Patriot indemnified the Company against any claim relating to these liabilities, which amounted to approximately $150 million at that time. The indemnification included any claim made by the U.S. Department of Labor (DOL) against the Company with respect to these obligations as a potentially liable operator under the Federal Coal Mine Health and Safety Act of 1969. The 2013 Agreement included Patriot’s affirmance of indemnities provided in the spin-off agreements, including the indemnity relating to such black lung liabilities; however, Patriot rejected this indemnity in its May 2015 bankruptcy.
By statute, the Company had secondary liability for the black lung liabilities related to Patriot’s workers employed by former subsidiaries of the Company. The Company’s accounting for the black lung liabilities related to Patriot is based on an interpretation of applicable statutes. Management believes that inconsistencies exist among the applicable statutes, regulations promulgated under those statutes and the saleDOL’s interpretative guidance. The Company has sought clarification from the DOL regarding these inconsistencies. The amount of surplus coal resources associatedthese liabilities could be reduced in the future. Whether the Company will ultimately be required to fund certain of those obligations in the future as a result of Patriot’s May 2015 bankruptcy remains uncertain. The amount of the liability, which was determined on an actuarial basis based on the best information available to the Company, was $82.3 million and $87.2 million at December 31, 2022 and 2021, respectively. The liability, which is classified as discontinued operations, is included in the Company’s consolidated balance sheets within “Accounts payable and accrued expenses” and “Other noncurrent liabilities.” In connection with the Company’s Millennium Mineactuarial valuation, the Company recorded mark-to-market adjustments of $20.6$2.7 million and $20.5 million, respectively. Operating profit forto decrease the third and fourth quarter of 2018 reflected $49.3 million and $17.1 million related to the provision for North Goonyella equipment loss, respectively. Operating profit for the first, second and third quarter of 2018 included steady income from equity affiliates of $22.0 million, $25.2 million and $17.2 million, respectively, due to favorable coal pricing at Middlemount. Operating profit for the fourth quarter of 2018 included acquisition costs related to the Shoal Creek Mine of $4.9 million. Income from continuing operations, net of income taxes for the first, second, third and fourth quarters of 2018 included steady interest expense of $36.3 million, $38.3 million, $38.2 million and $36.5 million respectively, partially offset by interest income of $7.2 million, $7.0 million, $10.1 million and $9.3 million in the first, second, third and fourth quarters of 2018, respectively. Income from continuing operations, net of income taxes for the first quarter of 2018 included a credit of $12.8 million for reorganization items, net due to a bankruptcy claims accrual adjustment in relation to the Company’s emergence from the Chapter 11 Cases. Income from continuing operations, net of income taxes for the fourth quarter of 2018 reflected $125.5 million of net mark-to-market gains on actuarially determined liabilities.
(22) Segment and the Kayenta Mine in the Western U.S. Mining segment shipped their final tons. Geographic Information
The Company also announced the closures of the Wildcat HiIls Underground and Somerville Central Mines in the Midwestern U.S. Mining segment, with both of those operations expecting to ship their final tons in 2020. Due to these changes, the Company will update its reportable segments beginning in the first quarter of 2020 to combine the Midwestern U.S. Mining segment with the Western U.S. Mining segment, which reflects the manner in which the chief operating decision maker (CODM) views the Company’s businesses going forward for purposes of reviewing performance, allocating resources and assessing future prospects and strategic execution. Beginning the first quarter of 2020, the Company will reportreports 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, revenuesrevenue 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.Alabama, USA. The mines in that segment utilize both surface and underground extraction processes to mine various qualities of metallurgical coal (low-sulfur, high Btu coal).coal. The metallurgical coal qualities include hard coking coal, semi-hard coking coal, semi-soft coking coal and pulverized coal injection coal.
| Peabody Energy Corporation | 2022 Form 10-K | F-59 | ||||||
The principal business of the Company’s thermal miningoperating 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 MidwesternOther U.S. Thermal Mining operations includereflect the aggregation of its Illinois, Indiana, New Mexico and IndianaColorado mining operations, whichoperations. 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). The Company’s Western U.S. Mining operations historically reflect the aggregation of its New Mexico, Arizona and Colorado mining operations. The mines in that segment are characterized by a mix of surface and underground mining extraction processes and coal with a mid-range sulfur content and Btu. Geologically, the Company’s Powder River Basin Mining operations mine sub-bituminous coal deposits its Midwestern U.S. Mining operations mine bituminous coal deposits and its WesternOther 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, including its technical and shared services functions, results from equity affiliates, corporate hedging activities, trading and brokerage activities, certain mining and export/transportation joint ventures, restructuring charges and activities associated with the optimization of its coal reserve and real estate holdings, minimum charges on certain transportation-related contracts, the closure of inactive mining sites and certain commercial matters.
The Company’s CODMchief operating decision maker, defined as its Chief Executive Officer, uses Adjusted EBITDA as the primary metric to measure the segments’ operating performance.performance and allocate resources. Adjusted EBITDA is a non-GAAP financial measure defined as income (loss) income from continuing operations before deducting net interest expense, income taxes, asset retirement obligation expenses and depreciation, depletion and amortization and reorganization items, net.amortization. Adjusted EBITDA is also adjusted for the discrete items that management excluded in analyzing the segments’ operating performance, as displayed in the reconciliation below. Management believes non-GAAP performance measures are used by investors to measure the Company’s operating performance and lenders to measure the Company’s ability to incur and service debt.performance. Adjusted EBITDA is not intended to serve as an alternative to U.S. GAAP measures of performance and may not be comparable to similarly-titled measures presented by other companies.
| Seaborne Thermal Mining | Seaborne Metallurgical Mining | Powder River Basin Mining | Other U.S. Thermal Mining | Corporate and Other | Consolidated | ||||||||||||||||||||||||||||||
| (Dollars in millions) | |||||||||||||||||||||||||||||||||||
| Revenue | $ | 1,345.6 | $ | 1,616.9 | $ | 1,065.5 | $ | 952.2 | $ | 1.7 | $ | 4,981.9 | |||||||||||||||||||||||
| Adjusted EBITDA | 647.6 | 781.7 | 68.2 | 242.4 | 104.8 | 1,844.7 | |||||||||||||||||||||||||||||
| Additions to property, plant, equipment and mine development | 38.8 | 84.8 | 59.1 | 35.3 | 3.5 | 221.5 | |||||||||||||||||||||||||||||
| Income from equity affiliates | — | — | — | — | (131.2) | (131.2) | |||||||||||||||||||||||||||||
Segment results for the year ended December 31, 2021 were as follows:
| Seaborne Thermal Mining | Seaborne Metallurgical Mining | Powder River Basin Mining | Other U.S. Thermal Mining | Corporate and Other | Consolidated | ||||||||||||||||||||||||||||||
| (Dollars in millions) | |||||||||||||||||||||||||||||||||||
| Revenue | $ | 934.0 | $ | 727.7 | $ | 971.2 | $ | 689.1 | $ | (3.7) | $ | 3,318.3 | |||||||||||||||||||||||
| Adjusted EBITDA | 353.1 | 178.2 | 134.9 | 164.2 | 86.3 | 916.7 | |||||||||||||||||||||||||||||
| Additions to property, plant, equipment and mine development | 88.6 | 25.1 | 41.4 | 24.2 | 3.8 | 183.1 | |||||||||||||||||||||||||||||
| Income from equity affiliates | — | — | — | — | (82.1) | (82.1) | |||||||||||||||||||||||||||||
Segment results for the year ended December 31, 2020 were as follows:
| Seaborne Thermal Mining | Seaborne Metallurgical Mining | Powder River Basin Mining | Other U.S. Thermal Mining | Corporate and Other | Consolidated | ||||||||||||||||||||||||||||||
| (Dollars in millions) | |||||||||||||||||||||||||||||||||||
| Revenue | $ | 711.8 | $ | 486.5 | $ | 991.1 | $ | 707.3 | $ | (15.6) | $ | 2,881.1 | |||||||||||||||||||||||
| Adjusted EBITDA | 163.2 | (130.2) | 194.8 | 168.4 | (137.4) | 258.8 | |||||||||||||||||||||||||||||
| Additions to property, plant, equipment and mine development | 100.7 | 50.8 | 13.2 | 23.3 | 3.4 | 191.4 | |||||||||||||||||||||||||||||
| Loss from equity affiliates | — | — | — | — | 60.1 | 60.1 | |||||||||||||||||||||||||||||
| Peabody Energy Corporation | ||||||||
| Successor | |||||||||||||||||||||||||||
| Seaborne Thermal Mining | Seaborne Metallurgical Mining | Powder River Basin Mining | Midwestern U.S. Mining | Western U.S. Mining | Corporate and Other | Consolidated | |||||||||||||||||||||
| (Dollars in millions) | |||||||||||||||||||||||||||
| Revenues | $ | 971.7 | $ | 1,033.1 | $ | 1,228.7 | $ | 669.7 | $ | 639.7 | $ | 80.5 | $ | 4,623.4 | |||||||||||||
| Adjusted EBITDA | 329.4 | 140.2 | 221.2 | 130.7 | 230.7 | (215.1 | ) | 837.1 | |||||||||||||||||||
| Additions to property, plant, equipment and mine development | 42.1 | 143.4 | 42.8 | 35.9 | 18.1 | 3.1 | 285.4 | ||||||||||||||||||||
| Income from equity affiliates | — | — | — | — | — | (3.4 | ) | (3.4 | ) | ||||||||||||||||||
| Successor | |||||||||||||||||||||||||||
| Seaborne Thermal Mining | Seaborne Metallurgical Mining | Powder River Basin Mining | Midwestern U.S. Mining | Western U.S. Mining | Corporate and Other | Consolidated | |||||||||||||||||||||
| (Dollars in millions) | |||||||||||||||||||||||||||
| Revenues | $ | 1,099.2 | $ | 1,553.0 | $ | 1,424.8 | $ | 801.0 | $ | 592.0 | $ | 111.8 | $ | 5,581.8 | |||||||||||||
| Adjusted EBITDA | 452.0 | 441.4 | 284.5 | 145.2 | 145.4 | (89.2 | ) | 1,379.3 | |||||||||||||||||||
| Additions to property, plant, equipment and mine development | 66.6 | 88.7 | 81.0 | 46.6 | 13.9 | 4.2 | 301.0 | ||||||||||||||||||||
| Federal coal lease expenditures | — | — | — | — | 0.5 | — | 0.5 | ||||||||||||||||||||
| Income from equity affiliates | — | — | — | — | — | (68.1 | ) | (68.1 | ) | ||||||||||||||||||
| Successor | |||||||||||||||||||||||||||
| Seaborne Thermal Mining | Seaborne Metallurgical Mining | Powder River Basin Mining | Midwestern U.S. Mining | Western U.S. Mining | Corporate and Other | Consolidated | |||||||||||||||||||||
| (Dollars in millions) | |||||||||||||||||||||||||||
| Revenues | $ | 772.5 | $ | 1,221.0 | $ | 1,178.7 | $ | 592.3 | $ | 440.7 | $ | 47.4 | $ | 4,252.6 | |||||||||||||
| Adjusted EBITDA | 306.6 | 414.9 | 278.8 | 124.4 | 131.8 | (111.2 | ) | 1,145.3 | |||||||||||||||||||
| Additions to property, plant, equipment and mine development | 39.2 | 56.0 | 32.6 | 21.7 | 13.8 | 3.3 | 166.6 | ||||||||||||||||||||
| Income from equity affiliates | — | — | — | — | — | (49.0 | ) | (49.0 | ) | ||||||||||||||||||
| Predecessor | |||||||||||||||||||||||||||
| Seaborne Thermal Mining | Seaborne Metallurgical Mining | Powder River Basin Mining | Midwestern U.S. Mining | Western U.S. Mining | Corporate and Other | Consolidated | |||||||||||||||||||||
| (Dollars in millions) | |||||||||||||||||||||||||||
| Revenues | $ | 224.8 | $ | 328.9 | $ | 394.3 | $ | 193.2 | $ | 149.7 | $ | 35.3 | $ | 1,326.2 | |||||||||||||
| Adjusted EBITDA | 75.6 | 109.6 | 91.7 | 50.0 | 50.0 | (35.6 | ) | 341.3 | |||||||||||||||||||
| Additions to property, plant, equipment and mine development | 2.3 | 5.2 | 19.3 | 2.8 | 3.1 | 0.1 | 32.8 | ||||||||||||||||||||
| Federal coal lease expenditures | — | — | — | — | 0.5 | — | 0.5 | ||||||||||||||||||||
| Income from equity affiliates | — | — | — | — | — | (15.0 | ) | (15.0 | ) | ||||||||||||||||||
Asset details are reflected at the division level only for the Company’s miningoperating segments and are not allocated between each individual segment as such information is not regularly reviewed by the Company’s CODM. Further, some assets service more than one segment within the division and an allocation of such assets would not be meaningful or representative on a segment by segment basis. Assets related to closed, suspended or otherwise inactive mines are included within the Corporate and Other category.
Assets as of December 31, 20192022 were as follows:
| Seaborne Mining | U.S. Thermal Mining | Corporate and Other | Consolidated | Seaborne Mining | U.S. Thermal Mining | Corporate and Other | Consolidated | |||||||||||||||||||||||||||||||
| (Dollars in millions) | (Dollars in millions) | |||||||||||||||||||||||||||||||||||||
| Total assets | $ | 2,001.3 | $ | 3,044.8 | $ | 1,496.7 | $ | 6,542.8 | Total assets | $ | 1,632.6 | $ | 1,359.4 | $ | 2,618.8 | $ | 5,610.8 | |||||||||||||||||||||
| Property, plant, equipment and mine development, net | 1,610.9 | 2,776.9 | 291.3 | 4,679.1 | Property, plant, equipment and mine development, net | 1,220.7 | 1,217.5 | 426.8 | 2,865.0 | |||||||||||||||||||||||||||||
| Operating lease right-of-use assets | 32.1 | 30.3 | 20.0 | 82.4 | Operating lease right-of-use assets | 20.5 | 0.5 | 5.9 | 26.9 | |||||||||||||||||||||||||||||
Assets as of December 31, 20182021 were as follows:
| Seaborne Mining | U.S. Thermal Mining | Corporate and Other | Consolidated | Seaborne Mining | U.S. Thermal Mining | Corporate and Other | Consolidated | |||||||||||||||||||||||||||||||
| (Dollars in millions) | (Dollars in millions) | |||||||||||||||||||||||||||||||||||||
| Total assets | $ | 2,044.6 | $ | 3,481.7 | $ | 1,897.4 | $ | 7,423.7 | Total assets | $ | 1,669.6 | $ | 1,318.5 | $ | 1,961.7 | $ | 4,949.8 | |||||||||||||||||||||
| Property, plant, equipment and mine development, net | 1,661.3 | 3,180.4 | 365.3 | 5,207.0 | Property, plant, equipment and mine development, net | 1,298.8 | 1,209.5 | 442.3 | 2,950.6 | |||||||||||||||||||||||||||||
| Operating lease right-of-use assets | Operating lease right-of-use assets | 19.2 | 3.3 | 13.0 | 35.5 | |||||||||||||||||||||||||||||||||
Assets as of December 31, 20172020 were as follows:
| Seaborne Mining | U.S. Thermal Mining | Corporate and Other | Consolidated | ||||||||||||
| (Dollars in millions) | |||||||||||||||
| Total assets | $ | 2,339.6 | $ | 3,846.5 | $ | 1,995.1 | $ | 8,181.2 | |||||||
| Property, plant, equipment and mine development, net | 1,501.7 | 3,361.0 | 249.2 | 5,111.9 | |||||||||||
| Seaborne Mining | U.S. Thermal Mining | Corporate and Other | Consolidated | ||||||||||||||||||||
| (Dollars in millions) | |||||||||||||||||||||||
| Total assets | $ | 1,763.0 | $ | 1,345.3 | $ | 1,558.8 | $ | 4,667.1 | |||||||||||||||
| Property, plant, equipment and mine development, net | 1,347.3 | 1,258.8 | 445.0 | 3,051.1 | |||||||||||||||||||
| Operating lease right-of-use assets | 30.8 | 3.5 | 15.6 | 49.9 | |||||||||||||||||||
| Peabody Energy Corporation | ||||||||
A reconciliation of consolidated income (loss) income from continuing operations, net of income taxes to Adjusted EBITDA follows:
| Year Ended December 31, | |||||||||||||||||
| 2022 | 2021 | 2020 | |||||||||||||||
| (Dollars in millions) | |||||||||||||||||
| Income (loss) from continuing operations, net of income taxes | $ | 1,317.4 | $ | 347.4 | $ | (1,859.8) | |||||||||||
| Depreciation, depletion and amortization | 317.6 | 308.7 | 346.0 | ||||||||||||||
| Asset retirement obligation expenses | 49.4 | 44.7 | 45.7 | ||||||||||||||
| Restructuring charges | 2.9 | 8.3 | 37.9 | ||||||||||||||
| Transaction costs related to joint ventures | — | — | 23.1 | ||||||||||||||
| Asset impairment | 11.2 | — | 1,487.4 | ||||||||||||||
| Changes in deferred tax asset valuation allowance and reserves and amortization of basis difference related to equity affiliates | (2.3) | (33.8) | 30.9 | ||||||||||||||
| Interest expense | 140.3 | 183.4 | 139.8 | ||||||||||||||
| Net loss (gain) on early debt extinguishment | 57.9 | (33.2) | — | ||||||||||||||
| Interest income | (18.4) | (6.5) | (9.4) | ||||||||||||||
| Net mark-to-market adjustment on actuarially determined liabilities | (27.8) | (43.4) | (5.1) | ||||||||||||||
| Unrealized losses on derivative contracts related to forecasted sales | 35.8 | 115.1 | 29.6 | ||||||||||||||
| Unrealized losses (gains) on foreign currency option contracts | 2.3 | 7.5 | (7.1) | ||||||||||||||
| Take-or-pay contract-based intangible recognition | (2.8) | (4.3) | (8.2) | ||||||||||||||
| Income tax (benefit) provision | (38.8) | 22.8 | 8.0 | ||||||||||||||
| Total Adjusted EBITDA | $ | 1,844.7 | $ | 916.7 | $ | 258.8 | |||||||||||
| Successor | Predecessor | |||||||||||||
| Year Ended December 31, 2019 | Year Ended December 31, 2018 | April 2 through December 31, 2017 | January 1 through April 1, 2017 | |||||||||||
| (Dollars in millions) | ||||||||||||||
| (Loss) income from continuing operations, net of income taxes | $ | (188.3 | ) | $ | 645.7 | $ | 713.1 | $ | (195.5 | ) | ||||
| Depreciation, depletion and amortization | 601.0 | 679.0 | 521.6 | 119.9 | ||||||||||
| Asset retirement obligation expenses | 58.4 | 53.0 | 41.2 | 14.6 | ||||||||||
| Gain on formation of United Wambo Joint Venture | (48.1 | ) | — | — | — | |||||||||
| Asset impairment | 270.2 | — | — | 30.5 | ||||||||||
| Provision for North Goonyella equipment loss | 83.2 | 66.4 | — | — | ||||||||||
North Goonyella insurance recovery - equipment (1) | (91.1 | ) | — | — | — | |||||||||
| Changes in deferred tax asset valuation allowance and reserves and amortization of basis difference related to equity affiliates | (18.8 | ) | (18.3 | ) | (17.3 | ) | (5.2 | ) | ||||||
| Interest expense | 144.0 | 149.3 | 119.7 | 32.9 | ||||||||||
| Loss on early debt extinguishment | 0.2 | 2.0 | 20.9 | — | ||||||||||
| Interest income | (27.0 | ) | (33.6 | ) | (5.6 | ) | (2.7 | ) | ||||||
| Net mark-to-market adjustment on actuarially determined liabilities | 67.4 | (125.5 | ) | (45.2 | ) | — | ||||||||
| Reorganization items, net | — | (12.8 | ) | — | 627.2 | |||||||||
| Gain on disposal of reclamation liability | — | — | (31.2 | ) | — | |||||||||
| Gain on disposal of Burton Mine assets | — | — | (52.2 | ) | — | |||||||||
| Break fees related to terminated asset sales | — | — | (28.0 | ) | — | |||||||||
| Unrealized (gains) losses on economic hedges | (42.2 | ) | (18.3 | ) | 23.0 | (16.6 | ) | |||||||
| Unrealized (gains) losses on non-coal trading derivative contracts | (1.2 | ) | 0.7 | 1.5 | — | |||||||||
| Fresh start coal inventory revaluation | — | — | 67.3 | — | ||||||||||
| Fresh start take-or-pay contract-based intangible recognition | (16.6 | ) | (26.7 | ) | (22.5 | ) | — | |||||||
| Income tax provision (benefit) | 46.0 | 18.4 | (161.0 | ) | (263.8 | ) | ||||||||
| Total Adjusted EBITDA | $ | 837.1 | $ | 1,379.3 | $ | 1,145.3 | $ | 341.3 | ||||||
The following table presents revenuesrevenue as a percent of total revenue from external customers by geographic region:
| Successor | Predecessor | |||||||||
| Year Ended December 31, 2019 | Year Ended December 31, 2018 | April 2 through December 31, 2017 | January 1 through April 1, 2017 | |||||||
| U.S. | 53.6 | % | 47.8 | % | 48.9 | % | 55.2 | % | ||
| Japan | 15.4 | % | 10.1 | % | 11.7 | % | 11.4 | % | ||
| Taiwan | 6.0 | % | 8.1 | % | 8.7 | % | 5.7 | % | ||
| Australia | 5.8 | % | 6.6 | % | 5.3 | % | 4.2 | % | ||
| China | 3.8 | % | 5.9 | % | 7.5 | % | 5.6 | % | ||
| South Korea | 2.9 | % | 3.1 | % | 1.1 | % | 0.5 | % | ||
| India | 1.2 | % | 6.2 | % | 6.7 | % | 2.7 | % | ||
| Other | 11.3 | % | 12.2 | % | 10.1 | % | 14.7 | % | ||
| Total | 100.0 | % | 100.0 | % | 100.0 | % | 100.0 | % | ||
| Year Ended December 31, | |||||||||||||||||
| 2022 | 2021 | 2020 | |||||||||||||||
| U.S. | 36.6 | % | 45.5 | % | 56.2 | % | |||||||||||
| Japan | 19.4 | % | 14.2 | % | 13.3 | % | |||||||||||
| Taiwan | 9.3 | % | 14.4 | % | 7.7 | % | |||||||||||
| Australia | 8.5 | % | 7.7 | % | 6.9 | % | |||||||||||
| India | 2.9 | % | 5.4 | % | 2.6 | % | |||||||||||
| Vietnam | 2.8 | % | 2.0 | % | 2.4 | % | |||||||||||
| Brazil | 2.8 | % | 0.9 | % | 0.1 | % | |||||||||||
| South Korea | 2.1 | % | 1.4 | % | 0.8 | % | |||||||||||
| Indonesia | 1.5 | % | 3.0 | % | 0.2 | % | |||||||||||
| Belgium | 1.3 | % | — | % | 0.3 | % | |||||||||||
| Chile | 1.1 | % | 0.3 | % | — | % | |||||||||||
| France | 1.1 | % | — | % | — | % | |||||||||||
| China | — | % | — | % | 3.8 | % | |||||||||||
| Other | 10.6 | % | 5.2 | % | 5.7 | % | |||||||||||
| Total | 100.0 | % | 100.0 | % | 100.0 | % | |||||||||||
The Company attributes revenue to individual countries based on the location of the physical delivery of the coal.
| Peabody Energy Corporation | ||||||||
PEABODY ENERGY CORPORATION
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS
| Description | Balance at Beginning of Period | Charged to Costs and Expenses | Deductions(1) | Other(2) | Balance at End of Period | |||||||||||||||||||||||||||||||||
| (Dollars in millions) | ||||||||||||||||||||||||||||||||||||||
| Year Ended December 31, 2022 | ||||||||||||||||||||||||||||||||||||||
| Reserves deducted from asset accounts: | ||||||||||||||||||||||||||||||||||||||
| Advance royalty recoupment reserve | $ | 0.3 | $ | (0.3) | $ | — | $ | — | $ | — | ||||||||||||||||||||||||||||
| Reserve for materials and supplies | 9.0 | 1.4 | (0.9) | — | 9.5 | |||||||||||||||||||||||||||||||||
| Tax valuation allowances | 2,120.8 | (583.8) | — | (86.0) | 1,451.0 | |||||||||||||||||||||||||||||||||
| Year Ended December 31, 2021 | ||||||||||||||||||||||||||||||||||||||
| Reserves deducted from asset accounts: | ||||||||||||||||||||||||||||||||||||||
| Advance royalty recoupment reserve | $ | 0.3 | $ | — | $ | — | $ | — | $ | 0.3 | ||||||||||||||||||||||||||||
| Reserve for materials and supplies | 10.4 | 0.6 | (2.0) | — | 9.0 | |||||||||||||||||||||||||||||||||
| Tax valuation allowances | 2,287.3 | (121.7) | — | (44.8) | 2,120.8 | |||||||||||||||||||||||||||||||||
| Year Ended December 31, 2020 | ||||||||||||||||||||||||||||||||||||||
| Reserves deducted from asset accounts: | ||||||||||||||||||||||||||||||||||||||
| Advance royalty recoupment reserve | $ | 0.3 | $ | — | $ | — | $ | — | $ | 0.3 | ||||||||||||||||||||||||||||
| Reserve for materials and supplies | 7.9 | 3.5 | (1.0) | — | 10.4 | |||||||||||||||||||||||||||||||||
| Tax valuation allowances | 2,068.4 | 373.2 | — | (154.3) | (3) | 2,287.3 | ||||||||||||||||||||||||||||||||
| Description | Balance at Beginning of Period | Charged to Costs and Expenses | Charged to Other Accounts | Deductions(1) | Other | Balance at End of Period | ||||||||||||||||||
| (Dollars in millions) | ||||||||||||||||||||||||
| Successor | ||||||||||||||||||||||||
| Year Ended December 31, 2019 | ||||||||||||||||||||||||
| Reserves deducted from asset accounts: | ||||||||||||||||||||||||
| Advance royalty recoupment reserve | $ | 0.3 | $ | — | $ | — | $ | — | $ | — | $ | 0.3 | ||||||||||||
| Reserve for materials and supplies | 0.2 | 8.9 | — | (1.2 | ) | — | 7.9 | |||||||||||||||||
| Allowance for doubtful accounts | 4.4 | (4.4 | ) | — | — | — | — | |||||||||||||||||
| Tax valuation allowances | 2,094.3 | (29.8 | ) | — | — | 3.9 | 2,068.4 | |||||||||||||||||
| Year Ended December 31, 2018 | ||||||||||||||||||||||||
| Reserves deducted from asset accounts: | ||||||||||||||||||||||||
| Advance royalty recoupment reserve | $ | — | $ | 0.3 | $ | — | $ | — | $ | — | $ | 0.3 | ||||||||||||
| Reserve for materials and supplies | 0.6 | 0.5 | — | (0.9 | ) | — | 0.2 | |||||||||||||||||
| Allowance for doubtful accounts | 4.6 | (0.2 | ) | — | — | — | 4.4 | |||||||||||||||||
| Tax valuation allowances | 2,432.5 | (275.0 | ) | — | — | (63.2 | ) | (4) | 2,094.3 | |||||||||||||||
| April 2 through December 31, 2017 | ||||||||||||||||||||||||
| Reserves deducted from asset accounts: | ||||||||||||||||||||||||
| Advance royalty recoupment reserve | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||
| Reserve for materials and supplies | — | 1.0 | — | (0.4 | ) | — | 0.6 | |||||||||||||||||
| Allowance for doubtful accounts | — | 4.6 | — | — | — | 4.6 | ||||||||||||||||||
| Tax valuation allowances | 3,288.4 | (744.9 | ) | — | — | (111.0 | ) | (3) | 2,432.5 | |||||||||||||||
| Predecessor | ||||||||||||||||||||||||
| January 1 through April 1, 2017 | ||||||||||||||||||||||||
| Reserves deducted from asset accounts: | ||||||||||||||||||||||||
| Advance royalty recoupment reserve | $ | 7.8 | $ | — | $ | (7.4 | ) | (2) | $ | (0.4 | ) | $ | — | $ | — | |||||||||
| Reserve for materials and supplies | 5.6 | 0.5 | (6.1 | ) | (2) | — | — | — | ||||||||||||||||
| Allowance for doubtful accounts | 13.1 | — | (12.8 | ) | (2) | (0.3 | ) | — | — | |||||||||||||||
| Tax valuation allowances | 4,037.5 | (777.2 | ) | 28.1 | (2) | — | — | 3,288.4 | ||||||||||||||||
(2)Includes the impact of changes in the Australian dollar exchange rates.
(3)Includes the impact of a decrease in Australia NOLs due to a cancellation of intercompany debt.
| 2022 Form 10-K | F-63 | |||||||