The release provides updated federal data for debates over coal mining, energy policy, public-land leasing and the environmental consequences of additional production. It does not, by itself, authorize mining, approve new mines or decide whether federal production will expand.

What the assessment says

The assessment separates reported reserves associated with active mines from the much larger estimate of available coal resources. Interior said the 4.2 billion short tons of reported reserves are tied to mines that are currently active, while the additional 356 billion short tons represent available resources identified beneath federal lands.

Those figures should not be read as a forecast of how much coal will be mined. Interior’s release does not establish how much of the estimated resource is economically recoverable or likely to be extracted. It also does not quantify projected greenhouse-gas emissions, water impacts or the assessment’s effect on future federal leasing.

Wyoming accounts for 87% of the reported reserves associated with active mines under federal lands, according to Interior. The state’s concentration of those reserves makes it the central location identified in the department’s summary, although the assessment covers federally managed public lands across the country.

Mine identified as the largest producer

The department identified the North Antelope Rochelle Mine in Wyoming’s Powder River Basin as the largest-producing federal-land coal mine. Interior also said the mine holds the largest reported reserves among the federal-land mines covered by the assessment.

The report was released by the Interior Department and prepared through the U.S. Geological Survey. Secretary of the Interior Doug Burgum and the Bureau of Land Management are among the federal entities connected to the department’s public-lands and resource-management responsibilities, but the approved release does not say that either agency has approved a new mining action as a result of this assessment.

Why the numbers matter

Coal resources beneath federal lands can become part of policy discussions about domestic energy supply, mining, public-land management and the future of federal leasing. The newly published figures give policymakers an updated government estimate of the potential resource base, while leaving separate questions about economics, permitting, environmental review and market demand unresolved.

For communities and workers connected to coal production, the assessment may be relevant to arguments about the long-term availability of federal coal. For people concerned about climate, water and land impacts, the report’s limits are equally important: the release does not calculate those effects or promise that the listed resources will be developed.

Interior announced a separate public-land policy change on Feb. 23, saying it had rescinded more than 80% of its prior National Environmental Policy Act regulations and moved most procedures into a departmental handbook. That announcement provides policy background for the department’s 2026 approach to public-land permitting and NEPA procedures, but the coal assessment itself does not state that it changes existing environmental-review or leasing requirements.

What happens next

The July 23 release is an assessment of coal resources and reserves, not a mining permit or lease decision. The approved department materials identify no new mine approval, expanded-production order or specific leasing deadline connected to the report.

Any future development would therefore involve decisions beyond the resource estimate. The assessment supplies information for those discussions, but it does not determine whether a particular resource can be mined, whether a lease will be offered or how environmental impacts would be evaluated.

Interior’s news index continued to list the assessment as a July 2026 department release on July 25. For now, the central development is the federal government’s updated accounting of coal beneath public lands—and the distinction between identifying a resource and authorizing its extraction.

The assessment also identifies at least 140 billion tons of coal resources in Alaska. Interior said the inventory could inform the management of public lands and national energy policy as the administration emphasizes domestic energy production.

What the assessment measures

The report covers coal reserves and resources beneath federally managed public lands across the United States. Its figures describe the estimated scale of the resource base; they do not represent a forecast that the coal will be mined or produced.

The 4.2-billion-short-ton figure applies to reported reserves associated with active mines on federal lands. A reserve estimate is distinct from the broader resource estimates in the assessment. The report’s additional estimate of 356 billion short tons covers available coal resources in the lower 48 states, while Alaska has at least 140 billion tons of identified coal resources.

Interior said that, if the resource base were produced, it would represent at least 600 years of current national coal consumption. That comparison describes the potential scale of the inventory, not a timetable for extraction or a prediction about future demand.

Wyoming accounts for most reported active-mine reserves

Wyoming contains 87% of the reported reserves associated with active mines on federal lands, according to the assessment. The North Antelope Rochelle Mine in Wyoming is identified as the largest-producing federal-land coal mine and as having the nation’s largest reported reserves.

The geographic concentration of reported reserves gives Wyoming a central place in the federal inventory. The additional resource estimates extend beyond the state, including the large amount identified in Alaska and the resources reported across the lower 48 states.

What it means for public-land policy

The release provides the federal government with a new resource inventory at a time when officials are weighing domestic energy production, energy security and how public lands should be managed. The information could be used in future discussions about mining and federal energy policy.

But the assessment itself does not approve new mines, authorize extraction of the full estimated resource base or determine whether mining would be environmentally feasible. The figures should not be read as saying that all identified coal resources are economically recoverable reserves.

That distinction matters for communities, companies and public-land users. An estimate of resources identifies coal that may be present or available for additional evaluation; it does not by itself establish that a project can proceed, that mining would be profitable or that environmental requirements have been met.

What happens next

Interior said the assessment could inform future management of public lands and energy policy. The approved announcement does not identify a specific mine approval, new leasing decision, production target or deadline that follows from the report.

For now, the July 23 release is a national accounting of estimated coal reserves and resources beneath federal lands. Any future decision to develop those resources would be separate from the assessment and would require actions not included in the report.

Those numbers describe coal underground, not coal that is already permitted, financed or ready for production. The inventory is a scientific assessment, not a lease sale, mine permit, production forecast or authorization to extract the fuel.

What the report counted

The 34 active federal-land mines produced more than 261 million short tons in 2024, according to the USGS report. A short ton equals 2,000 pounds. Surface mining is used at 23 of the mines, while 11 use underground methods.

The mines are concentrated in the West. Thirty-one of the 34 are west of the Mississippi River, and those mines account for more than 98 percent of the reported reserves. Wyoming has 14 federal-land mines and produces more coal from federal lands than any other state.

The Powder River Basin, which spans parts of northeastern Wyoming and southeastern Montana, has 14 federal-land mines identified by USGS: 12 in Wyoming and two in Montana. Interior says Wyoming mines contain 87 percent of the reported reserves associated with active federal-land mines.

Most of the mines produce thermal coal for electricity. Three Alabama mines produce metallurgical coal used in steelmaking, one Colorado mine produces coal for cement, and one Utah mine is idled.

Reserves and resources are not the same

Reported reserves are tied to active mines and represent coal identified in connection with current mining operations. Available coal resources are a broader geological category. They describe coal identified as present and potentially available beneath federal lands, but they do not guarantee that it can be mined profitably or without significant technical, legal or environmental limits.

That distinction matters because the 355-billion-ton figure should not be described as the amount of coal the United States can immediately mine. Economic conditions, transportation, mine design, permitting, environmental review, market demand and reclamation requirements would all affect whether particular deposits could be developed.

USGS separately estimates at least 140 billion short tons of identified available coal resources beneath federal lands in Alaska. The report says Alaska’s total coal resources could ultimately be as high as 5.5 trillion short tons, but it cautions that additional geological mapping is needed. The 5.5-trillion-ton figure is a possible upper estimate for total resources, not the identified available-resource amount.

Why the inventory matters now

The report arrives as the Trump administration pursues a broader effort to expand coal production from public lands. The Associated Press reported that federal officials are considering new coal leases covering more than 2,600 square miles of federal land in the Powder River Basin in Montana and Wyoming.

That leasing effort remains preliminary. A Bureau of Land Management spokesperson told AP that the proposal could change after public comment, and the agency has not said how much interest mining companies have or how quickly any new mines could open.

The Interior Department said the resources could supply national needs for at least 600 years if produced at the current rate of consumption. That is agency framing based on current use, not a forecast that the coal will be mined or that national electricity demand will remain unchanged.

What the report does not do

The inventory does not authorize mining, reopen leasing, determine economic viability, settle environmental questions or establish future production. Individual projects would still require federal leasing decisions, public participation, environmental review, permits, market commitments and reclamation plans.

What to watch next

The practical checkpoints are federal leasing notices, public-comment periods, environmental reviews, mine applications, evidence of buyer interest and reclamation requirements. Those steps will determine whether any of the identified coal moves from a geological estimate toward an operating mine.

For now, the USGS report establishes a new federal baseline for the size and location of coal resources beneath public lands. It does not show that the deposits are economical, that companies will seek them or that new mining will occur.

Sources

• U.S. Geological Survey coal inventory
• USGS Circular 1570
• U.S. Department of the Interior release
• Associated Press leasing report

In its Electricity Mid-Year Update 2026, published July 23, the IEA forecast global electricity-demand growth of 3.6% in 2026 and 3.8% in 2027, compared with 3% growth in 2025. These are forecasts, not final results.

Why electricity use is accelerating

The IEA attributes the increase to overlapping structural trends, including industrial activity, wider appliance ownership, air-conditioning demand, heat pumps, electric vehicles and expanding data-center capacity. Global electricity consumption is projected to reach 30,700 terawatt-hours in 2027, up from 28,600 terawatt-hours in 2025.

The growth is uneven. China’s electricity demand is forecast to rise 5.5% in 2026, supported by manufacturing activity and electric-vehicle charging. India’s demand is forecast to rebound to 7% after weather-related weakness in 2025. U.S. demand is expected to increase by close to 2%, led in part by data centers, air conditioning and industry. European Union demand is also forecast to grow about 2%, supported by electrification, colder winter weather early in the year and cooling needs during heatwaves.

By contrast, the IEA says some price-sensitive LNG-importing markets, including Bangladesh and Pakistan, have adopted conservation measures that curtailed electricity consumption.

How the LNG disruption reached power markets

The IEA says the temporary loss of LNG flows through the Strait of Hormuz removed nearly 20% of global LNG supply and produced significant price volatility. Gas prices in Asia and Europe reached their highest levels since the 2022-23 energy crisis, although prices later moderated from their March highs.

The gas-market outlook assumes that the Strait fully reopens in the third quarter of 2026 and that operations at undamaged regional facilities are restored by early in the fourth quarter. That is an assumption in the IEA forecast, not a completed outcome. The duration and reliability of the reopening remain important risks.

Additional LNG from North America and other exporters has helped ease market tightness, but higher gas prices have still changed how some power systems meet demand. The IEA expects gas-fired generation to remain broadly flat in 2026 while coal-fired output increases in several Asian and European markets as utilities switch fuels.

The price effects have differed sharply by region. Average spot wholesale electricity prices in the European Union and Japan rose by more than 30% year over year in the second quarter of 2026. U.S. wholesale prices were broadly unchanged, while prices in India rose by less than 10%. Australia’s average wholesale price was about 45% lower, which the IEA links to strong renewable generation and rapidly expanding battery storage.

Wholesale electricity prices are not the same as household electricity bills. Retail effects depend on contracts, taxes, subsidies, network charges and regulation. Higher generation costs can nevertheless feed into bills, cooling expenses and industrial prices. Gas-market stress can also affect fertilizer production and, indirectly, food costs.

Why renewables can overtake coal while coal use rises

The IEA projects that renewables will become the largest source of global electricity generation in 2026 after reaching near parity with coal in 2025. Renewable generation is forecast to grow by more than 8% this year, with renewables’ share of global generation rising from 33% in 2025 to 37% by 2027.

Solar photovoltaic generation is expected to add about 600 terawatt-hours in 2026 and overtake wind as the world’s second-largest renewable source after hydropower.

That projection does not mean fossil fuels disappear. Electricity demand is rising quickly enough that new renewable generation does not immediately replace every unit of coal- or gas-fired power. When LNG becomes scarce or expensive, utilities can turn to coal to keep electricity flowing. The result can be a cleaner global generation mix overall alongside a short-term increase in coal generation.

The IEA also forecasts that power-sector carbon dioxide emissions will rise by about 1% in 2026 before flattening in 2027. The projected increase reflects fuel switching from gas to coal and weather-related increases in coal- and oil-fired generation during the first half of the year. The agency expects renewables, nuclear power and natural gas to help displace coal globally in 2027.

What could stabilize the outlook

The next pressure points include the reopening and reliability of the Strait of Hormuz, LNG deliveries from suppliers outside the Gulf, summer and winter weather, the possibility of a stronger-than-expected El Niño, nuclear-plant availability and further coal switching.

The IEA says grid flexibility will become increasingly important as renewable generation expands. Battery storage, demand response, transmission upgrades, stronger price signals and more efficient use of existing infrastructure can help systems manage periods of surplus renewable power, sharp evening demand peaks and sudden fuel-price shocks.

Nuclear generation is also expected to increase in 2026 and accelerate in 2027 as new reactors come online and delayed projects are completed, although maintenance outages and construction delays limit near-term growth.

For consumers and businesses, the practical test is whether power systems can absorb rising electricity use without passing every fuel and weather shock directly into prices. The IEA’s next updates will show whether LNG flows normalize, renewable additions keep pace, coal switching persists and the 2026-27 forecasts hold.

Sources

• IEA: Electricity Mid-Year Update 2026 executive summary
• Reuters: Global power demand to accelerate in 2026 and 2027

One major change would expand the index-based valuation option to arm’s-length Federal gas and NGL sales. The proposal would also switch the gas benchmark from the highest bidweek price to the average bidweek price, which ONRR says would better reflect market value and simplify reporting.

ONRR also wants to remove the default provision and the associated misconduct definition from the regulations. The agency says the old language has created ambiguity and inconsistent application. The proposal also sets out the standard of review and timeliness for Director-level appeals.

The preliminary analysis attached to the draft estimates a net annual decrease of about $331 million in royalty collections if the rule is finalized, along with about $2 million in reduced administrative costs for lessees. The public-inspection copy shows the rule was scheduled for Federal Register publication on June 30, 2026, and comments are due 60 days after publication.

What happens next

The immediate question is whether the final rule should keep these valuation changes, scale them back, or drop them. For energy companies, state revenue watchers, and taxpayers, the practical issue is how much federal royalty revenue Interior is willing to trade for simpler reporting rules.

Sources

• U.S. Department of the Interior press release on proposed royalty rule
• Federal Register public inspection draft: proposed ONRR royalty valuation rule
• Federal Register issue for June 30, 2026