PEABODY ENERGY CORP

Previous wording

The following discussion of the Company’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.

Current wording

The following discussion of the Company’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 the chief operating decision maker as the primary metric to measure each of the 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.

Previous wording

Within the global coal industry, supply and demand for its products and the supplies used for mining continue to be impacted by the ongoing Russian-Ukrainian conflict. As future developments related to the Russian-Ukrainian conflict and geopolitical instability in key energy producing regions are unknown, the global coal industry data for the three months ended March 31, 2024 presented herein may not be indicative of their ultimate impacts.

Current wording

Within the global coal industry, supply and demand for its products and the supplies used for mining continue to be impacted by the ongoing Russian-Ukrainian conflict. As future developments related to the Russian-Ukrainian conflict and geopolitical instability in key energy producing regions are unknown, the global coal industry data for the six months ended June 30, 2024 presented herein may not be indicative of their ultimate impacts.

Previous wording

Within the seaborne metallurgical coal market, coking coal prices retreated from a high base during the three months ended March 31, 2024. Outside of India and China, metallurgical coal demand was hampered by thin steel margins. In India robust economic output supported steel making profitability; while in China steel demand was mixed but generally weaker, pressured by real estate sector performance, and domestic metallurgical coal prices declined in response. Meanwhile, Australian high-quality coking coal showed signs of supply improvement after a period of extended production disruptions and relatively high segment prices. This incremental volume of high-quality coking coal was reportedly placed in the seaborne market at progressively lower prices during the three months ended March 31, 2024. In other metallurgical coal market segments, such as pulverized coal injection, prices also retreated during the period however not to the extent of high-quality coking coal given reduced steel making productivity targets under thin margin conditions had already been priced into these segments. In the coming period, improving steel margins, economic stimulus measures and seasonal restocking patterns may lend support to metallurgical coal market pricing. Overall, the market for metallurgical coal remains finely balanced and exposed to volatility, influenced by the rate of recovery of exports from Australia and economic performance in China, India and elsewhere.

Current wording

Within the seaborne metallurgical coal market, coking coal prices have retreated from a high base during the six months ended June 30, 2024. Parts of the global steel market have reported tepid demand and thin profit margins during this period, restricting demand growth for metallurgical coal. In India, steel production was disrupted due to election activities and more recently the onset of the monsoon season; while in China, steel production was mixed with a weak property market slowing demand, partially offset by economic stimulus targeting the real estate sector. Australian high-quality coking coal showed signs of supply improvement during the six months ended June 30, 2024 which has weighed on coking coal prices, however periodic price support has been observed via various supply side disruptions, including rail and port maintenance curtailing exports in Queensland, the restriction of U.S. exports in Baltimore, Maryland and low domestic coal production in China. The June 2024 incident at the Grosvenor Mine in Queensland, Australia has further limited global exports. Despite these constraints, coking coal supply proved sufficient to meet demand during the period. In the PCI segment, prices were initially under pressure early in the year from reduced steel making productivity targets under thin margin conditions, but have since found support from shifting of trade flows from Russian to Australian supply amidst newly announced sanctions. In the coming period, seasonal restocking patterns and ongoing economic stimulus may lend support to metallurgical coal pricing. Overall, the market for metallurgical coal remains finely balanced and exposed to volatility, influenced by the rate of exports from Australia and economic performance in China, India and elsewhere.

Previous wording

Within the seaborne thermal coal market, global thermal coal prices were rangebound during the three months ended March 31, 2024, finding support in Asian markets due to potential supply disruptions following new Russian sanctions. In China, overall total generation demand has been elevated while domestic coal production has declined, which has driven stronger coal import demand year-over-year through the three months ended March 31, 2024. In India, strong growth in coal generation has supported increased import demand, despite elevated domestic coal production. Overall, global thermal coal markets remain turbulent amid ample supply and seasonal demand requirements in the Northern Hemisphere, as well as volatile global natural gas markets.

Current wording

Within the seaborne thermal coal market, global thermal coal prices were rangebound during the six months ended June 30, 2024, driven by healthy supply meeting elevated demand in Asian markets. In China, overall total generation demand has been elevated while domestic coal production has declined, which has driven stronger coal import demand year-over-year through the six months ended June 30, 2024. In India, strong growth in coal generation has supported increased import demand, despite elevated domestic coal production. Overall, global thermal coal markets remain turbulent amid ample supply and seasonal demand requirements in the Northern Hemisphere, as well as volatile global natural gas markets.

Previous wording

In the U.S., overall electricity demand increased approximately 4% year-over-year. Through the three months ended March 31, 2024, electricity generation from thermal coal has declined year-over-year due to low natural gas prices and stronger renewable generation, despite higher overall electricity demand. Coal’s share of electricity generation has declined to approximately 15% for the three months ended March 31, 2024, while wind and solar’s combined generation share is at 17% and the share of natural gas generation has increased to 41%. While U.S. coal inventories declined in January, these levels have reversed and increased through March 31, 2024, resulting in stockpiles slightly above levels seen at the end of 2023. During the three months ended March 31, 2024, utility consumption of PRB coal increased approximately 6% compared to the prior year period.

Current wording

In the U.S., overall electricity demand increased approximately 5% year-over-year. Through the six months ended June 30, 2024, electricity generation from thermal coal has increased slightly year-over-year driven by higher overall electricity demand and despite low natural gas prices and stronger renewable generation. Coal’s share of electricity generation has declined to approximately 14% for the six months ended June 30, 2024, while wind and solar’s combined generation share is at 19% and the share of natural gas generation has decreased slightly to 40%. U.S. coal inventories have declined through June 30, 2024, resulting in stockpiles slightly below levels seen at the end of 2023. During the six months ended June 30, 2024, utility consumption of PRB coal was unchanged compared to the prior year period.

Previous wording

The Company entered into a definitive agreement dated October 26, 2023, to acquire the southern part of the Wards Well tenements (Wards Well area) which are adjacent to the Company’s Centurion Mine in Queensland, Australia. The acquisition was completed on April 16, 2024 for cash consideration of approximately $134 million and a contingent royalty of up to $200 million. The royalty will only be payable once the Company has recovered its investment and development costs of the Wards Well area and if the average sales price achieved exceeds certain thresholds. No royalty is payable if the Company does not commence mining in the Wards Well area.

Current wording

The agreement also includes an initial contingent royalty of up to $200 million. The royalty will only be payable once the Company has recovered its investment and development costs of Wards Well and if the average sales price achieved exceeds certain thresholds. No royalty is payable if the Company does not commence mining Wards Well.

Previous wording

Three Months Ended March 31, 2024 Compared to the Three Months Ended March 31, 2023

Current wording

Three and Six Months Ended June 30, 2024 Compared to the Three and Six Months Ended June 30, 2023

Previous wording

The decrease in income from continuing operations, net of income taxes for the three months ended March 31, 2024 compared to the same period in the prior year ($238.4 million) was driven by lower revenue ($380.4 million) due to no unrealized mark-to-market gains from derivative contracts related to forecasted sales in the current year, lower seaborne coal pricing and volume decreases in the U.S. thermal segments. This unfavorable variance was partially offset by a lower tax provision ($97.9 million) and operating costs and expenses ($32.4 million).

Current wording

The decrease in income from continuing operations, net of income taxes for the six months ended June 30, 2024 compared to the same period in the prior year ($231.7 million) was driven by lower revenue ($607.2 million) due to no unrealized mark-to-market gains from derivative contracts related to forecasted sales in the current year, lower seaborne coal pricing and volume decreases in the U.S. thermal segments. This unfavorable variance was partially offset by a lower tax provision ($132.7 million), the current year insurance recovery related to the 2023 event at the Shoal Creek Mine ($109.5 million), lower operating costs and expenses ($90.5 million) and lower year-over-year provision for losses at the NARM and Shoal Creek Mines ($30.0 million).

Previous wording

(2)Includes revenue-based production taxes and royalties; excludes depreciation, depletion and amortization; asset retirement obligation expenses; selling and administrative expenses; restructuring charges; asset impairment; amortization of take-or-pay contract-based intangibles; and certain other costs related to post-mining activities.

Current wording

(2)Includes revenue-based production taxes and royalties; excludes depreciation, depletion and amortization; asset retirement obligation expenses; selling and administrative expenses; restructuring charges; asset impairment; amortization of take-or-pay contract-based intangibles; insurance recoveries; and certain other costs related to post-mining activities.

Previous wording

Seaborne Thermal. Segment revenue decreased during the three months ended March 31, 2024 compared to the same period in the prior year due to unfavorable realized prices ($94.9 million), partially offset by favorable export volumes ($32.3 million).

Current wording

Seaborne Thermal. Segment revenue decreased during the three and six months ended June 30, 2024 compared to the same periods in the prior year due to unfavorable realized prices ($117.4 million and $217.8 million, respectively), partially offset by favorable export volumes ($25.4 million and $63.2 million, respectively).

Previous wording

Seaborne Metallurgical. Segment revenue decreased during the three months ended March 31, 2024 compared to the same period in the prior year due to unfavorable realized prices ($89.9 million), offset by favorable volumes ($48.5 million) driven by increased production at the Shoal Creek Mine.

Current wording

Seaborne Metallurgical. Segment revenue decreased during the three months ended June 30, 2024 compared to the same period in the prior year due to unfavorable realized prices ($56.8 million) and mix variances ($21.4 million). Segment revenue decreased during the six months ended June 30, 2024 compared to the same period in the prior year due to unfavorable realized prices ($181.1 million), offset by favorable volume and mix variances ($61.5 million) driven by increased production at the Shoal Creek Mine.

Previous wording

Powder River Basin. Segment revenue decreased during the three months ended March 31, 2024 compared to the same period in the prior year primarily due to unfavorable volumes ($48.0 million) resulting from decreased demand driven by low natural gas pricing and mild weather.

Current wording

Powder River Basin. Segment revenue decreased during the three and six months ended June 30, 2024 compared to the same periods in the prior year due to unfavorable volumes ($38.2 million and $85.7 million, respectively) resulting from decreased demand driven by low natural gas pricing and mild weather.

Previous wording

Other U.S. Thermal. Segment revenue decreased during the three months ended March 31, 2024 compared to the same period in the prior year due to unfavorable volumes ($67.2 million) resulting from decreased demand driven by low natural gas pricing and mild weather, partially offset by increased sales contract cancellation settlements ($12.4 million).

Current wording

Other U.S. Thermal. Segment revenue increased during the three months ended June 30, 2024 compared to the same period in the prior year due to favorable realized prices ($3.2 million). Segment revenue decreased during the six months ended June 30, 2024 compared to the same period in the prior year due to unfavorable volumes ($69.4 million) resulting from decreased demand driven by low natural gas pricing and mild weather, partially offset by increased sales contract cancellation settlements ($13.1 million).

Previous wording

Corporate and Other. Segment revenue decreased during the three months ended March 31, 2024 compared to the same period in the prior year due to no unrealized mark-to-market gains from derivative contracts related to forecasted sales in the current year ($118.7 million) as all derivative contracts settled in 2023; lower results from trading activities ($31.8 million); and prior year revenue related to the Company’s assignment of rights to its excess port and rail capacity ($19.2 million) as discussed in Note 15. “Other Events” to the accompanying unaudited condensed consolidated financial statements.

Current wording

Corporate and Other. Segment revenue decreased during the three months ended June 30, 2024 compared to the same period in the prior year due to no unrealized mark-to-market gains from derivative contracts related to forecasted sales in the current year ($40.3 million) as all derivative contracts settled in 2023; offset by favorable results from trading activities ($19.0 million). Segment revenue decreased during the six months ended June 30, 2024 compared to the same period in the prior year due to no unrealized mark-to-market gains from derivative contracts related to forecasted sales in the current year ($159.0 million); prior year revenue related to the Company’s assignment of rights to its excess port and rail capacity ($19.2 million) as discussed in Note 15. “Other Events” to the accompanying unaudited condensed consolidated financial statements; and lower results from trading activities ($12.8 million).

Previous wording

Seaborne Thermal. Segment Adjusted EBITDA decreased during the three months ended March 31, 2024 compared to the same period in the prior year as a result of lower realized prices net of sales price sensitive costs ($89.8 million), partially offset by favorable volume and mix variances ($21.1 million).

Current wording

Seaborne Thermal. Segment Adjusted EBITDA decreased during the three and six months ended June 30, 2024 compared to the same periods in the prior year as a result of lower realized prices net of sales price sensitive costs ($106.0 million and $200.8 million, respectively), partially offset by favorable volume and mix variances ($15.4 million and $39.2 million, respectively).

Previous wording

Powder River Basin. Segment Adjusted EBITDA decreased during the three months ended March 31, 2024 compared to the same period in the prior year due to unfavorable volumes ($24.1 million) and elevated overburden removal costs ($10.5 million), offset by lower costs for materials, services, repairs and labor ($11.0 million) and favorable commodity pricing ($6.9 million).

Current wording

Powder River Basin. Segment Adjusted EBITDA decreased during the three and six months ended June 30, 2024 compared to the same periods in the prior year due to unfavorable volumes ($14.1 million and $44.9 million, respectively) and increased lease spend ($3.4 million and $5.4 million, respectively), offset by lower costs for materials, services, repairs and labor ($9.7 million and $22.3 million, respectively) and favorable commodity pricing ($1.4 million and $8.2 million, respectively).

Previous wording

Other U.S. Thermal. Segment Adjusted EBITDA decreased during the three months ended March 31, 2024 compared to the same period in the prior year due to unfavorable volumes ($39.5 million), offset by increased sales contract cancellation settlements ($12.4 million) and lower costs for materials, services, repairs and labor ($8.2 million).

Current wording

Other U.S. Thermal. Segment Adjusted EBITDA decreased during the three and six months ended June 30, 2024 compared to the same periods in the prior year due to unfavorable volumes ($22.3 million and $59.7 million, respectively), offset by favorable mine sequencing ($2.4 million and $11.5 million, respectively) and increased sales contract cancellation settlements (six months, $13.1 million).

Previous wording

(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 Centurion Mine and expenses related to the Company’s other commercial activities.

Current wording

(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 Centurion Mine, the impact of foreign currency remeasurement and expenses related to the Company’s other commercial activities.

Previous wording

Corporate and Other Adjusted EBITDA decreased during the three months ended March 31, 2024 compared to the same period in the prior year due to unfavorable trading results ($40.2 million); prior year revenue related to the Company’s assignment of rights to its excess port and rail capacity ($19.2 million) as discussed in Note 15. “Other Events” to the accompanying unaudited condensed consolidated financial statements; and the unfavorable net impact of foreign currency rate changes ($15.0 million).

Current wording

Corporate and Other Adjusted EBITDA decreased during the six months ended June 30, 2024 compared to the same period in the prior year due to unfavorable trading results ($25.5 million); prior year revenue related to the Company’s assignment of rights to its excess port and rail capacity ($19.2 million) as discussed in Note 15. “Other Events” to the accompanying unaudited condensed consolidated financial statements; and the unfavorable net impact of foreign currency rate changes ($5.4 million).

Previous wording

The increases in the weighted-average depletion rate per ton for both the Seaborne Metallurgical and the Other U.S. Thermal segments during the three months ended March 31, 2024 compared to the same period in the prior year reflect the impact of volume and mix variances across the segments.

Current wording

The increases in the weighted-average depletion rate per ton for both the Seaborne Metallurgical and the Other U.S. Thermal segments during the three and six months ended June 30, 2024 compared to the same periods in the prior year reflect the impact of volume and mix variances across the segments.

Previous wording

Interest Income. The increase in interest income during the three months ended March 31, 2024 was primarily due to higher cash balances, including restricted cash balances on which the Company earns interest, and higher interest rates in the current year.

Current wording

Interest Income. The decrease in interest income during the three months ended June 30, 2024 was primarily due to lower average cash balances, including restricted cash balances on which the Company earns interest, in the current year.

Previous wording

Income Tax Provision. The decrease in the income tax provision during the three months ended March 31, 2024 compared to the same period in the prior year was primarily due to lower pretax income. Refer to Note 8. “Income Taxes” to the accompanying unaudited condensed consolidated financial statements for additional information.

Current wording

Income Tax Provision. The decrease in the income tax provision during the three and six months ended June 30, 2024 compared to the same periods in the prior year was primarily due to lower pretax income. Refer to Note 8. “Income Taxes” to the accompanying unaudited condensed consolidated financial statements for additional information.

Previous wording

Net Income Attributable to Noncontrolling Interests. The decrease in the results attributable to noncontrolling interests during the three months ended March 31, 2024 compared to the same period in the prior year was primarily due to a decline in the financial results of Peabody’s majority-owned Wambo operations in which there is an outside non-controlling interest.

Current wording

Net Income Attributable to Noncontrolling Interests. The decrease in the results attributable to noncontrolling interests during the three and six months ended June 30, 2024 compared to the same periods in the prior year was primarily due to a decline in the financial results of Peabody’s majority-owned Wambo operations in which there is an outside non-controlling interest.

Previous wording

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 144.9 million and 161.4 million for the three months ended March 31, 2024 and 2023, respectively.

Current wording

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 142.8 million and 159.0 million for the three months ended June 30, 2024 and 2023, respectively, and 143.8 million and 160.2 million for the six months ended June 30, 2024 and 2023, respectively.

Previous wording

Revenue per Ton and Adjusted EBITDA Margin per Ton are equal to revenue by segment and Adjusted EBITDA by segment, respectively, divided by segment tons sold. Costs per Ton is equal to Revenue per Ton less Adjusted EBITDA Margin per Ton.

Current wording

Revenue per Ton and Adjusted EBITDA Margin per Ton are equal to revenue by segment and Adjusted EBITDA by segment (excluding insurance recoveries), respectively, divided by segment tons sold. Costs per Ton is equal to Revenue per Ton less Adjusted EBITDA Margin per Ton.

Previous wording

Available Free Cash Flow is defined as operating cash flow minus investing cash flow and distributions to noncontrolling interests; plus/minus changes to restricted cash and collateral and other anticipated expenditures. See the table below for a reconciliation of Available Free Cash Flow to its most comparable measure under U.S. GAAP.

Current wording

Available Free Cash Flow is defined as operating cash flow less investing cash flow and distributions to noncontrolling interests; plus/minus changes to restricted cash and collateral and other anticipated expenditures. See the table below for a reconciliation of Available Free Cash Flow to its most comparable measure under U.S. GAAP.

Previous wording

On December 20, 2018, the EPA proposed to revise the 2015 NSPS to modify the minimum requirements for newly constructed coal-fired units from partial CCUS to efficiency-based standards. (83 Fed. Reg. 65,424 (Dec. 20, 2018)). In contrast to the 2015 rule, the proposed rule defined BSER as the most efficient demonstrated steam cycle in combination with the best operating practices. The EPA indicated that the primary reason for revising BSER was the high cost and limited geographic availability of CCUS technology. On May 23, 2023, however, the EPA published a notice of proposed rulemaking addressing NSPS from new, modified and reconstructed fossil-fuel steam EGUs. In contrast to the 2018 proposed rule, the 2023 proposed rule didnot propose to amend the 2015 NSPS for coal-fired EGUs. Status reports filed with the D.C. Circuit in North Dakota v. EPAindicate that litigation on the 2015 rule should remain in abeyance pending the EPA’s action on the 2018 proposed rule and the 2023 proposed rule. As indicated in the following section, the EPA signed a final rule based on the 2023 proposed rule on April 24, 2024. This final rule did not amend the 2015 NSPS for coal-fired EGUs, but indicated that the EPA will continue to consider whether or not to make revisions to that rule in the future.

Current wording

On December 20, 2018, the EPA proposed to revise the 2015 NSPS to modify the minimum requirements for newly constructed coal-fired units from partial CCUS to efficiency-based standards. (83 Fed. Reg. 65,424 (Dec. 20, 2018)). In contrast to the 2015 rule, the proposed rule defined BSER as the most efficient demonstrated steam cycle in combination with the best operating practices. The EPA indicated that the primary reason for revising BSER was the high cost and limited geographic availability of CCUS technology. On May 23, 2023, however, the EPA published a notice of proposed rulemaking addressing NSPS from new, modified and reconstructed fossil-fuel steam EGUs. In contrast to the 2018 proposed rule, the 2023 proposed rule didnot propose to amend the 2015 NSPS for coal-fired EGUs. Status reports filed with the D.C. Circuit in North Dakota v. EPAindicate that litigation on the 2015 rule should remain in abeyance pending the EPA’s action on the 2018 proposed rule and the 2023 proposed rule. As indicated in the following section, on May 9, 2024, the EPA published the final rule in the Federal Register based on the 2023 proposed rule. This final rule did not amend the 2015 NSPS for coal-fired EGUs, but indicated that the EPA will continue to consider whether or not to make revisions to that rule in the future.

Previous wording

EPA Regulation of Greenhouse Gas Emissions from New and Existing Fossil Fuel-Fired EGUs. On April 24, 2024, the EPA signed a pre-publication version of final rules for new, modified and reconstructed fossil fuel-fired EGUs. This rule package consists of four elements: (1) revised NSPS for controlling CO 2 emissions from new and reconstructed stationary combustion turbines; (2) revised NSPS for fossil fuel-fired steam EGUs that undertake a large modification; (3) emission guidelines for existing fossil fuel-fired steam EGUs; and (4) repeal of the Affordable Clean Energy rule promulgated in 2019.

Current wording

EPA Regulation of Greenhouse Gas Emissions from New and Existing Fossil Fuel-Fired EGUs. On May 9, 2024, the EPA published a final rule for new, modified and reconstructed fossil fuel-fired EGUs in the Federal Register. The final rule consists of four elements: (1) revised NSPS for controlling CO 2 emissions from new and reconstructed stationary combustion turbines; (2) revised NSPS for fossil fuel-fired steam EGUs that undertake a large modification; (3) emission guidelines for existing fossil fuel-fired steam EGUs; and (4) repeal of the Affordable Clean Energy rule promulgated in 2019.

Previous wording

With respect to existing fossil fuel-fired steam EGUs (primarily coal-fired) the EPA determined that the BSER that is adequately demonstrated is carbon capture and sequestration (CCS) with 90% capture of CO 2 emissions. Pursuant to the final rules, existing fossil fuel-fired steam EGUs that intend to operate in the long-term will be required to comply with a CO 2 emission rate based on CCS with 90% capture by January 1, 2032. Existing fossil fuel-fired steam EGUs that will permanently cease operations by January 1, 2039 are not subject to emission standards based on 90% CO 2 capture, but will need to meet an emission rate based on co-firing with 40% natural gas by January 1, 2030. (This translates into a 16% reduction in CO 2 emissions determined from a unit-specific baseline). Existing fossil fuel-fired steam EGUs that permanently cease operations by January 1, 2032 are exempt from these requirements.

Current wording

With respect to existing fossil fuel-fired steam EGUs (primarily coal-fired) the EPA determined that the BSER that is adequately demonstrated is carbon capture and sequestration (CCS) with 90% capture of CO 2 emissions. Pursuant to the final rule, existing fossil fuel-fired steam EGUs that intend to operate in the long-term will be required to comply with a CO 2 emission rate based on CCS with 90% capture by January 1, 2032. Existing fossil fuel-fired steam EGUs that will permanently cease operations by January 1, 2039 are not subject to emission standards based on 90% CO 2 capture, but will need to meet an emission rate based on co-firing with 40% natural gas by January 1, 2030. (This translates into a 16% reduction in CO 2 emissions determined from a unit-specific baseline). Existing fossil fuel-fired steam EGUs that permanently cease operations by January 1, 2032 are exempt from these requirements.

Previous wording

All requirements related to existing affected units in the final rules – whether fired by coal, oil or natural gas – will be imposed through state plans that are permitted to take into account the remaining useful life of a generating unit when determining appropriate controls. Under the final rules, such plans must provide for the implementation and enforcement of the NSPS, but states may apply less stringent standards of performance in certain conditions, as specified in EPA regulations. States are also permitted to impose more stringent standards. In addition, the final rules include several “reliability” mechanisms to allow states to provide alternative emission limitations or compliance date extensions in order maintain adequate electric generation resources and grid reliability.

Current wording

All requirements related to existing affected units in the final rule – whether fired by coal or natural gas – will be imposed through state plans that are permitted to take into account the remaining useful life of a generating unit when determining appropriate controls. Under the final rule, such plans must provide for the implementation and enforcement of the NSPS, but states may apply less stringent standards of performance in certain conditions, as specified in EPA regulations. States are also permitted to impose more stringent standards. In addition, the final rule includes several “reliability” mechanisms to allow states to provide alternative emission limitations or compliance date extensions in order to maintain adequate electric generation resources and grid reliability.

Previous wording

Finally, as part of the final rules, any newly constructed stationary combustion turbine (SCT), where construction or reconstruction of the unit was commenced after May 23, 2023, will be subject to CO 2 emission limits based on whether it is considered to be a low load, intermediate load or base load EGU. In addition, for affected base load SCTs, a second phase emission standard applies based on 90% CCS as of January 1, 2032. Any new fossil-fuel steam EGU (where construction or reconstruction was commenced after June 18, 2014) will need to comply with standards promulgated in 2015.

Current wording

Finally, as part of the final rule, any newly constructed stationary combustion turbine (SCT), where construction or reconstruction of the unit was commenced after May 23, 2023, will be subject to CO 2 emission limits based on whether it is considered to be a low load, intermediate load or base load EGU. In addition, for affected base load SCTs, a second phase emission standard applies based on 90% CCS as of January 1, 2032. Any new fossil-fuel steam EGU (where construction or reconstruction was commenced after June 18, 2014) will need to comply with standards promulgated in 2015.

Previous wording

Effluent Limitations Guidelines for the Steam Electric Power Generating Industry. In 2015, the EPA published a final rule setting requirements for wastewater discharge from EGUs. In 2020, the EPA finalized revisions to certain requirements in the 2015 rule. On April 24, 2024, the EPA signed a pre-publication version of a final rule that would establish more stringent standards for flue gas desulfurization wastewater, bottom ash transport water, combustion residual leachate and legacy wastewater discharged from certain surface impoundments. The final revised effluent limitations guidelines would significantly increase costs for many coal-fueled steam electric power plants. In addition, the recently finalized final rule allows EGUs that commit to ceasing coal combustion by December 31, 2034, to comply with less stringent wastewater discharge requirements during the interim. The final rule could influence fuel switching or additional coal generating unit retirements by the end of 2034.

Current wording

Effluent Limitations Guidelines for the Steam Electric Power Generating Industry. In 2015, the EPA published a final rule setting requirements for wastewater discharge from EGUs. In 2020, the EPA finalized revisions to certain requirements in the 2015 rule. On May 9, 2024, the EPA published a final rule that would establish more stringent standards for flue gas desulfurization wastewater, bottom ash transport water, combustion residual leachate and legacy wastewater discharged from certain surface impoundments. The final revised effluent limitations guidelines would significantly increase costs for many coal-fueled steam electric power plants. In addition, the recently finalized final rule allows EGUs that commit to ceasing coal combustion by December 31, 2034, to comply with less stringent wastewater discharge requirements during the interim. The final rule is subject to numerous legal challenges that have been consolidated in the Eighth Circuit. If the Eighth Circuit affirms the final rule, it could influence fuel switching or additional coal generating unit retirements by the end of 2034.

Previous wording

Rules for Disposal of Coal Combustion Residuals (CCR) from Electric Utilities; Federal CCR Permit Program and Revisions to Closure Requirements. On February 20, 2020, as required by the Water Infrastructure Improvements for the Nation Act, the EPA proposed a federal permitting program for the disposal of CCR in surface impoundments and landfills. Under the proposal, the EPA would directly implement the permit program in Indian Country and at CCR units located in states that have not submitted their own CCR permit program for approval. The proposal includes requirements for federal CCR permit applications, content and modification, as well as procedural requirements. The comment period for the EPA’s proposal ended on April 20, 2020. Although the EPA had planned to finalize this rule in 2021, the EPA now expects to issue a final rule around March 2026. Separately, on August 28, 2020 and November 12, 2020, the EPA finalized two sets of amendments to its 2015 CCR rule to partially address the D.C. Circuit’s 2018 decision holding that certain provisions of that rule were not sufficiently protective. On April 24, 2024, the EPA signed a pre-publication version of additional amendments to the 2015 CCR rule that further address aspects of the D.C. Circuit’s 2018 decision. Finally, the EPA is still considering whether to finalize additional revisions to the 2015 CCR Rule related to closure of CCR units.

Current wording

Rules for Disposal of Coal Combustion Residuals (CCR) from Electric Utilities; Federal CCR Permit Program and Revisions to Closure Requirements. On February 20, 2020, as required by the Water Infrastructure Improvements for the Nation Act, the EPA proposed a federal permitting program for the disposal of CCR in surface impoundments and landfills. Under the proposal, the EPA would directly implement the permit program in Indian Country and at CCR units located in states that have not submitted their own CCR permit program for approval. The proposal includes requirements for federal CCR permit applications, content and modification, as well as procedural requirements. The comment period for the EPA’s proposal ended on April 20, 2020. Although the EPA had planned to finalize this rule in 2021, the EPA now expects to issue a final rule around October 2024. Separately, on August 28, 2020 and November 12, 2020, the EPA finalized two sets of amendments to its 2015 CCR rule to partially address the D.C. Circuit’s 2018 decision holding that certain provisions of that rule were not sufficiently protective. On May 8, 2024, the EPA published a final rule containing additional amendments to the 2015 CCR rule that further address aspects of the D.C. Circuit’s 2018 decision. Finally, the EPA is still considering whether to finalize additional revisions to the 2015 CCR Rule related to closure of CCR units.

Previous wording

Implementation of the rule for existing sources (accomplished through state implementation plans) was challenged in several U.S. Courts of Appeal, resulting in different court opinions and in requirements being implemented in some states, but stayed in others. On December 20, 2023, the U.S. Supreme Court issued an order for oral argument regarding applications for an emergency stay of the rule. The U.S. Supreme Court held oral argument on February 21, 2024.

Current wording

Implementation of the rule for existing sources (accomplished through state implementation plans) was challenged in several U.S. Courts of Appeal, resulting in different court opinions and in requirements being implemented in some states, but stayed in others. On June 27, 2024, the U.S. Supreme Court issued a stay of the rule in 11 states pending the disposition of a petition for review of the rule in the D.C. Circuit and any subsequent timely petition for certiorari filed with and granted by the U.S. Supreme Court.

Previous wording

Regional Haze. The CAA 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 man-made 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. On March 29, 2024, the EPA published a proposed consent decree under which deadlines would be established for the EPA to take final action to approve, disapprove or conditionally approve, in whole or in part, state regional haze implementation plans for 34 states (at various dates from June 28, 2024 to December 31, 2026).

Current wording

Regional Haze. The CAA 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 man-made 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. On March 29, 2024, the EPA published a proposed consent decree under which deadlines would be established for the EPA to take final action to approve, disapprove or conditionally approve, in whole or in part, state regional haze implementation plans for 34 states (at various dates from June 28, 2024 to December 31, 2026). The EPA subsequently filed a motion to approve the consent judgement in the U.S. District Court for the District of Columbia which remains pending.

Previous wording

Federal Coal Leasing Moratorium. 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 April 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 Finding of No Significant Impact (FONSI) remedied the prior 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 FONSI and reinstated the moratorium until completion of a sufficient NEPA analysis. On appeal, the U.S. Court of Appeals for the Ninth Circuit reversed the district court on February 21, 2024, explaining that the lawsuit was mooted by the Department of Interior’s April 2021 order revoking Order 3349. The Ninth Circuit directed the district court to dismiss the case as moot.

Current wording

Federal Coal Leasing Moratorium. 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 April 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 Interior’s issuance of an Environmental Assessment and Finding of No Significant Impact (FONSI) remedied the prior 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 FONSI and reinstated the moratorium until completion of a sufficient NEPA analysis. On appeal, the U.S. Court of Appeals for the Ninth Circuit (Ninth Circuit) reversed the district court on February 21, 2024, explaining that the lawsuit was mooted by the Department of Interior’s April 2021 order revoking Order 3349. The Ninth Circuit directed the district court to dismiss the case as moot.

Previous wording

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 Peabody’s costs or its ability to mine some of its properties in accordance with its current mining plans. During the Trump Administration, the Departments of the Interior and Commerce finalized five rules aiming to streamline and update the ESA. But in June 2021, the 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 agencies issued proposed rules on June 22, 2023, and they issued pre-publication versions of three final revised rules on March 27, 2024.

Current wording

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 Peabody’s costs or its ability to mine some of its properties in accordance with its current mining plans. During the Trump Administration, the Departments of Interior and Commerce finalized five rules aiming to streamline and update the ESA. But in June 2021, the 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 agencies issued proposed rules on June 22, 2023, and they published three final revised rules on April 5, 2024.

Previous wording

SEC Climate-Related Disclosures. On March 6, 2024, the SEC adopted final rules it expects will enhance and standardize climate-related disclosures by public companies and in public offerings. Specifically, the final rules will require disclosure of, among other things, climate-related risks that have had or are reasonably likely to have a material impact on a public company’s business strategy, results of operations or financial condition; certain greenhouse gas (GHG) emissions associated with a public company along with, in many cases, an attestation report by a GHG emissions attestation provider; and certain climate-related financial metrics to be included in a company’s audited financial statements. The final rules were challenged by multiple parties, and the cases were consolidated into a judicial review by the U.S. Court of Appeals for the Eighth Circuit. On April 4, 2024, the SEC voluntarily stayed implementation of the final rules. The Company is assessing the potential impact of the final rules.

Current wording

SEC Climate-Related Disclosures. On March 6, 2024, the SEC adopted final rules it expects will enhance and standardize climate-related disclosures by public companies and in public offerings. Specifically, the final rules will require disclosure of, among other things, climate-related risks that have had or are reasonably likely to have a material impact on a public company’s business strategy, results of operations or financial condition; certain greenhouse gas (GHG) emissions associated with a public company along with, in many cases, an attestation report by a GHG emissions attestation provider; and certain climate-related financial metrics to be included in a company’s audited financial statements. The final rules were challenged by multiple parties, and the cases were consolidated into a judicial review by the Eighth Circuit. On April 4, 2024, the SEC voluntarily stayed implementation of the final rules pending such judicial review. The Company is assessing the potential impact of the final rules.

Previous wording

Under the NSW 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.

Current wording

New South Wales (NSW) Environmental. Under the NSW Environmental Planning and Assessment Act 1979 (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.

Previous wording

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. The New South Wales government is currently considering fifty-eight recommendations of a 2023 independent review of the BC Act. Any changes to the BC Act have the potential to affect approval processes for future NSW mining projects.

Current wording

On August 25, 2017, the Biodiversity Conservation Act 2016 (BC Act) commenced in NSW 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. On July 18, 2024, following an independent review of the BC Act, the NSW government announced it would amend the BC Act toreform the biodiversity offsets scheme by introducing anew statutory standard requiring mining proponents to demonstrate how they have genuinely avoided and minimized impacts to biodiversity and removing the option for major mining proponents to meet a credit obligation through a commitment to ecological mine site rehabilitation. When enacted, these and other proposed changes have the potential to affect approval processes for future NSW mining projects.