Global warming and heat stress risk close in on the Tour de France

An analysis of 50 years of climate data shows that the race has so far avoided the most extreme conditions, although the risk is steadily increasing

Barcelona Institute for Global Health (ISGlobal)

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The progressive rise in temperatures poses a growing threat to the staging of summer sporting events in Europe and, more specifically, to the Tour de France, due to the increasing risk of heat stress for athletes. This is one of the conclusions of a study published in Scientific Reports, which analysed climate data associated with more than 50 editions of the French race. The research was led by the French National Research Institute for Sustainable Development (IRD) within the European project TipESM, in collaboration with institutions such as the London School of Hygiene & Tropical Medicine (LSHTM) and the Barcelona Institute for Global Health (ISGlobal), a centre supported by the ”la Caixa” Foundation.

The aim of the newly published study was to assess under which heat stress risk levels the Tour de France has taken place at different locations and dates between 1974 and 2023. The results show that, at the times and places where the race is held, heat stress risk has increased steadily over the years, with the most recent decade accumulating the highest number of extreme heat episodes. Despite this trend, the Tour has so far managed to avoid conditions of maximum health risk, in some cases by only a matter of days or tenths of a degree.

 

An ‘extremely fortunate’ race

“In our analysis, we observe that the city of Paris, for example, has crossed the high-risk threshold for heat on five occasions in July, four of them since 2014. Other cities have experienced many days of extreme heat in July, but thankfully not on the date of a Tour de France stage,” explains Ivana Cvijanovic, researcher at IRD and first author of the study.

“In a way, we can say that it is an extremely fortunate race, but with record-breaking heatwaves becoming more frequent, it is only a matter of time before the Tour encounters extreme heat stress day that will test existing safety protocols,” she adds.

 

Regions at higher risk

The researchers found that episodes of dangerous heat levels have been most common around Toulouse, Pau and Bordeaux in southwestern France, and around Nîmes and Perpignan in the southeast. They also warn that locations such as Paris and Lyon are increasingly crossing the high-risk heat threshold, becoming new heat stress hotspots. “Extra caution should be exercised when planning stages in these regions,” says Desislava Petrova, researcher at ISGlobal.

By contrast, classic mountain stage locations such as the Col du Tourmalet and Alpe d’Huez have historically remained within low to moderate heat stress risk thresholds, with no recorded episodes of extreme heat risk to date.

Regarding the time of day, the analysis shows that morning hours remain the safest part of the day, while high heat stress levels can persist until late in the afternoon.

These patterns highlight the need to adapt schedules, routes and safety protocols in order to reduce risks for both cyclists and event staff and spectators.

 

Heat, a growing risk for all sports

In this study, the researchers use the Tour de France to illustrate the broader challenge that rising temperatures driven by climate change pose to the organisation of summer sporting events, particularly in elite sport.

Heat not only affects athletic performance but can also pose a serious risk to athletes’ health. For this reason, the Union Cycliste Internationale (UCI), like FIFA and other international sports federations, has implemented safety protocols that assess heat risk and trigger protective measures, such as hydration or cooling breaks in football. However, each federation defines its own risk thresholds, and no universal standard currently exists across sports.

 

The need for physiological data to refine risk assessment

 “Science still has many unanswered questions about how the human body responds to heat, and even more so in the case of elite athletes, who face sustained physical exertion while also having physical conditioning and training levels well above those of the general population,” says James Begg, researcher at Galson Sciences. “To investigate sport-specific vulnerabilities, we would need access to anonymised physiological data that would allow us to go beyond heat indices alone.”

 

Methodology

Many heat safety protocols used by international sports federations are based on a heat index known as the Wet Bulb Globe Temperature (WBGT), which combines several meteorological variables — including air temperature, relative humidity, solar radiation and wind — to estimate heat-related health risk.

To conduct the study, the research team retrieved historical meteorological records for 12 locations frequently visited by the Tour de France, as well as for all July dates corresponding to the different editions of the race. Using these data, they calculated WBGT values and analysed the occasions on which the high-risk category in the UCI protocol (above 28 °C WBGT) was reached.

Table 1. The highest Wet Bulb Globe Temperature (WBGT) values recorded at 1500 h from 1974 to 2023: Race dates vs. All days in July

	Highest WBGT Values
Location	TdF race dates	All days in July
Paris	26.8 °C in 2002	28.8 °C in 2019
Nimes	27.9 °C in 2019	30 °C in 2020
Bordeaux	28.7 °C in 1995	30.1 °C in 2019
Toulouse	27.5 °C in 2003	29.7 °C in 2020
Col du Tourmalet	23 °C in 2006	25.9 °C in 2019
Alpe d’Huez	20.1 °C in 1992	22.7 °C in 2015
Pau	27.8 °C in 1995	28.8 °C in 2019
Nice	22.7 °C in 1975	27.6 °C in 2018
Grenoble	22.5 °C in 2014	26.4 °C in 2018

 

Reference

Cvijanovic I, Begg JD, Mistry MN, Petrova D, Brimicombe C, Sultan B. The future of European outdoor summer sports through the lens of 50 years of the Tour de France. Scientific Reports. 2026 (in press).

---

Journal

Scientific Reports

DOI

10.1038/s41598-025-30129-8 

Method of Research

Observational study

U$A

Big Tech Is Raiding the Energy Sector to Power the AI Boom

By Felicity Bradstock - Feb 22, 2026

• Nearly 100 GW of new data center capacity is expected by 2030, doubling global capacity and sharply increasing electricity demand.
• 
  
• Tech firms are hiring energy specialists at a record pace to secure power supply and accelerate infrastructure buildout.
• 
  
• Utilities risk talent shortages, potentially worsening grid constraints amid surging AI-driven electricity consumption.
• 
  

As the tech sector expands, in line with the growing global demand for advanced technologies, it appears that many companies may be poaching workers from the energy sector. Hiring skilled employees from the energy industry could help tech companies to advance their ambitions for developing giant new data centres to power artificial intelligence (AI) and other technologies, without the need for retraining costs.

Tech companies worldwide are investing heavily in the development and expansion of the data centres that they require to deploy advanced technologies. With AI being incorporated into countless search engines, websites, and applications, tech companies cannot develop their new data centres fast enough. This has led several companies to invest in major new projects, as well as establish deals with energy firms to provide power for these centres.

Almost 100 GW of new data centres are expected to be added from 2026 to 2030, doubling the global capacity. The world’s data centre sector will likely expand at a 14 percent CAGR through 2030. By the end of the decade, AI could represent half of all workloads, compared to around a quarter of data centre workloads in 2025. This will have a meaningful impact on the power sector, with some countries feeling the strain more than others.

Data centres contributed around 1.5 percent of global electricity consumption in 2024, marking a 12 percent year-on-year increase over the last five years. The global electricity demand from data centres is expected to almost double by 2030. In the United States, rapid sectoral expansion means that data centres were expected to require 22 percent more power by the end of 2025 than just one year earlier. This figure is forecast to increase threefold by 2030. The development and expansion of data centres is expected to require around $3 trillion in investment by 2030.

Tech companies are increasingly looking to the energy industry to support sectoral expansion, using the skills and expertise of those working in the power sector to develop their projects. Several firms are investing in workforce expansion to prepare for the accelerated rollout of AI and other technologies.

One of the main restrictions to scaling AI so far has been gaining sufficient access to power. According to a recent report, energy-related hiring by the tech sector increased by 34 percent year on year in 2024, and a similar figure was seen in 2025. Tech companies are turning to energy experts to help them overcome the power supply hurdle by developing their in-house energy supplies. Some larger tech firms have absorbed whole energy companies to achieve this. When it comes to the acquisition of energy firms, Google’s parent company, Alphabet, plans to acquire data centre company Intersect, at a projected cost of $4.75 billion.

Several of the big tech names, such as Microsoft, Google, and Amazon, have led the trend to date. Operational roles in energy procurement, markets, grid interface and strategy have increased, according to recruiters. Meanwhile, reports suggest that Microsoft has employed 570 energy workers since 2022. Microsoft took on General Electric’s former CFO, Carolina Dybeck Happe, in 2024 as the firm’s COO. Amazon is thought to have employed 605 energy sector workers, putting it ahead of other tech firms. In addition, Google has hired around 340 people from the energy sector.

New employees come from a diverse range of energy backgrounds, from oil and gas to academia. However, many individual employees poached from the energy sector have been given temporary contracts. This is likely because they are expected to be required for the infrastructure development and the setting up of large-scale data centres, but they may not be needed after this has been achieved.

The CEO of The Green Recruitment Company, Daniel Smart, suggested that, as most tech firms have never built an energy project before, they prefer to outsource. “They’ll outsource the construction of it, and possibly even outsource the running of it and just buy the energy,” said Smart. In “phase two”, tech firms will attempt to improve the energy efficiency of data centres, which could support the creation of some permanent roles, according to Smart.

Meanwhile, utilities may find it increasingly difficult to hire the talent required to support grid expansion, as tech companies have the funds required to provide more attractive offers to energy workers. This could exacerbate the anticipated power supply and demand gap of the coming years and lead to the need to invest heavily in training programmes for the next generation of employees.

The rapid expansion of the tech sector’s data centres is driving many companies to hire talent from the energy sector to support development. With little skills in this field, tech firms are looking to energy experts to understand how to effectively develop this business and improve efficiency. This could make it increasingly more difficult for utilities and energy companies to retain talent, which could have a negative knock-on effect on grid expansion.

By Felicity Bradstock for Oilprice.com

Spoiler alert: The reason your power bill is through the roof isn't data centers — yet

Photo by Vitaly Gariev on Unsplash

Naveena Sadasivam, 

Grist

February 20, 2026 

It’s no secret that U.S. electricity prices have been rising over the last few years: The average residential energy bill in 2025 was roughly 30 percent higher than in 2021. This jump is largely in line with the overall inflation Americans have experienced during this period. As the cost of groceries, gas, and housing has increased, so too has the cost of electricity.

But there are big differences from state to state and region to region. Some places — like California and the Northeast — have seen mammoth price increases that outpaced inflation, while costs have held steady in other parts of the country, or even fallen in relative terms. Nearly everywhere, though, rising electricity costs have strained the budgets of low-income households in particular, since they spend a much larger share of their earnings on energy compared to wealthier Americans.

Higher energy bills have also become a political flashpoint. Over the past year, rising electricity prices have helped push voters to the polls, and politicians have taken note. In Virginia and New Jersey, newly elected governors campaigned heavily on reining in utility bills. In Georgia, incumbent utility regulators were booted out by voters, who elected two Democrats to the positions for the first time in two decades.

A wide range of culprits have been blamed for the surge in electricity prices, with energy-hungry data centers shouldering much of the criticism. Tariffs, aging power plants, and renewable energy mandates have also come under fire. But the reality is far more nuanced, according to recent research from the Lawrence Berkeley National Laboratory and the latest price data from the federal government’s Energy Information Administration. Electricity prices are shaped by a complex mix of factors, including how utilities are structured, how regulators oversee them, regional divergences in fuel prices, and how often the grid is stressed by heat waves or cold snaps. In many states, the biggest driver is the rising cost of maintaining and upgrading grids to survive more extreme weather — the unglamorous work of replacing old poles and wires.

But the forces driving high bills in California aren’t the same as those affecting households in Connecticut or Arizona. In this piece, we highlight one key driver of recent price trends in each region of the country. (The regions below are organized alphabetically, with individual entries for Alaska, California, Hawaiʻi, the Midwest, the Northeast, the Pacific Northwest, the Southeast/Mid-Atlantic, the Southwest/Mountain West, and Texas.) While the dynamics of every utility bill are different — including those within the same state — recent data demonstrates the many challenges ahead as public officials promise a laser focus on energy affordability.

Alaska


Key factor: Geographic isolation

Alaska’s electricity prices are among the highest in the country, largely because the state’s power grid operates in isolation. Unlike utilities in the lower 48 states, Alaska’s providers can’t import electricity from neighboring states or Canada when demand spikes or supply runs short. That isolation limits flexibility and drives up costs. Utilities also have to spread the expense of generating and transmitting power across a relatively small customer base. The state’s primary grid, known as the Railbelt, serves about 75 percent of Alaska’s population. Beyond it, more than 200 microgrids power rural communities, many of which rely heavily on diesel generators. These structural challenges contribute to electricity rates that are roughly 40 percent higher than the national average.

Electricity prices have been rising in the state over the past decade, even after adjusting for overall inflation. A study by researchers at the Alaska Center for Energy and Power found that residential rates for Railbelt customers increased by about 23 percent between 2011 and 2019. Rural customers saw a roughly 9 percent increase during the same period.


While more recent data charting electricity prices adjusted for inflation isn’t readily available, energy costs are likely to grow in the state. That’s because Alaska depends on natural gas for electricity generation and heating, and it relies on the Cook Inlet basin for natural gas. With supplies dwindling in that reserve, the state is expected to face a shortage soon. If it chooses to import natural gas, it will be much more easily affected by price swings in the natural gas market. State regulators have also approved a 7.4 percent interim rate increase for the Golden Valley Electric Association, the primary utility that serves the Fairbanks area. A full rate case review is underway, and a final decision on the rate will be made in early 2027.

California

Key factor: Wildfires

Californians have long paid above-average electricity prices. Since the 1980s, rates in the Golden State have typically been at least 10 percent higher than the national average. For decades, however, those higher per-kilowatt-hour prices were largely offset by lower electricity use as a result of the state’s relatively temperate climate. In other words, electricity in California cost more per unit, but residents consumed far less than households in many other states, keeping average monthly bills relatively low. That began to shift in the mid-2010s when the state began experiencing more frequent and larger wildfires. Since then, electricity prices have outpaced consumption, leading to exorbitantly high energy bills.

Between 2019 and 2024, California had the largest increase in retail electricity prices of all U.S. states. Monthly energy bills in 2024 averaged $160, roughly 13 percent higher than the national average. Much of that increase has been driven by the soaring cost of infrastructure upgrades aimed at reducing wildfire risk, along with rising wildfire-related insurance and liability costs. After the 2018 Camp Fire, PG&E declared bankruptcy, citing $30 billion in estimated liabilities. Utilities have also poured billions of dollars into replacing aging transmission and distribution lines and expanding the grid to meet growing demand.

California’s high rate of rooftop solar adoption has also played a complicated role in rising prices. As more customers install rooftop solar, they purchase less electricity from the grid. That leaves utilities with the same fixed infrastructure costs — but fewer kilowatt-hours over which to spread them. The result: higher per-unit rates for customers who remain more dependent on grid power. Since renters and low-income Californians are less likely to benefit from residential solar, rising electricity rates hit them harder.

Hawaiʻi


Key factor: Oil dependence

Hawaiʻi has the highest electricity bills in the country. Average residential rates rose about 8 percent between 2019 and 2024, even after adjusting for overall inflation, and the typical household now pays more than $200 per month for electricity.

Those high costs are rooted in the state’s unique energy system. Hawaiʻi remains heavily dependent on oil to generate power, and many of its oil-fired plants are aging and relatively inefficient. That reliance ties electricity prices directly to global oil markets. Hawaiian Electric, the state’s primary utility, purchases crude oil on the open market and pays to have it refined before it is burned to produce electricity — meaning fluctuations in both crude prices and refining costs show up on customers’ bills.While oil prices have eased in the past couple of years, they spiked sharply in 2022 following Russia’s invasion of Ukraine, driving up fuel costs and, in turn, electricity rates. Refining costs on the islands have also risen in recent years, adding further pressure to household bills. Fuel and equipment must also be shipped thousands of miles from the mainland — and often transported between islands — adding significant logistical costs. Hawaiʻi’s power grids are also small and isolated. Electricity generated on one island cannot easily be transmitted to another, limiting flexibility and preventing the kind of resource sharing common on the continental grid. Together, those structural constraints help keep electricity prices in Hawaiʻi persistently high.

Midwest

(Illinois, Indiana, Iowa, Kansas, Michigan, Minnesota, Missouri, North Dakota, Nebraska, Ohio, Oklahoma, South Dakota, and Wisconsin.)

Key factor: Wind energy

The Midwest and Great Plains states saw only modest changes — and sometimes even declines — in inflation-adjusted retail electricity prices per kilowatt-hour between 2019 and 2024. Average monthly electricity bills typically fall between $110 and $130.

This stability is largely a renewable energy success story: Many Midwestern states are now deeply reliant on wind power. Wind supplies more than 40 percent of electricity in Iowa and South Dakota, and more than 35 percent in Kansas. Investments in utility-scale wind and solar have helped shield consumers from price shocks tied to natural gas volatility, since renewables have no fuel costs and can reduce exposure to sudden spikes in gas prices. Research also shows that these investments can lower wholesale electricity prices by displacing higher-cost generation during periods of high wind and solar output.

Northeast
(Connecticut, Maine, Massachusetts, New Hampshire, New Jersey, New York, Pennsylvania, Rhode Island, and Vermont)

Key factor: Natural gas prices

Aside from California and Hawaiʻi, northeastern states experienced some of the steepest increases in retail prices between 2019 and 2024. Prices in New York and Maine rose more than 10 percent over the last few years. Connecticut residents pay nearly $200 per month for electricity.

The region’s heavy reliance on natural gas as both a home heating fuel and a source of utility-scale electricity is a major driver of high energy bills, especially in winter. When temperatures drop, demand for natural gas surges as homes and businesses burn more fuel for heating. Power plants are then forced to compete with those heating needs for the same constrained supply. (Gas has to be transported to the region via pipelines that stretch as far as Texas.) With no easy way to bring in additional gas, prices spike, and those increases ripple through to power bills.

A combination of forces has worsened natural gas constraints in recent years, pushing electricity prices even higher, particularly during cold snaps. More households in the region are switching to heat pumps and buying EVs, driving up demand for power. International energy policies, like increasing U.S. exports of liquefied natural gas and the global gas crunch caused by Russia’s invasion of Ukraine, are driving up fuel costs stateside. Utilities in the Northeast, like those elsewhere in the country, are also pouring money into infrastructure upgrades, and those investments are being passed on to customers through higher bills.

Pacific Northwest
(Idaho, Montana, Oregon, Washington)

Key factor: Hydropower

Retail electricity prices in the Pacific Northwest rose only modestly over the last few years, at least compared to the country’s general rise in the cost of living. Inflation-adjusted prices in Washington and Oregon increased by about 5 percent between 2019 and 2024, while Idaho and Montana saw slight declines. In 2024, average monthly energy bills across the four states ranged from about $105 to $130, roughly in line with the national average. (This is not to say that customers haven’t noticed growing totals on their energy bills; the Energy Information Administration estimated that Oregon’s average retail price increased by 30 percent between 2020 and 2024, which is roughly in line with overall inflation over the last several years.)

So why has the region been largely insulated from the inflation-adjusted cost spikes that have struck neighboring areas like California? Hydropower. Abundant, low-cost hydroelectric generation has long kept energy bills in the Pacific Northwest — and the climate impact of the region’s power generation — among the lowest in the country. And while utilities in these states are facing rising costs tied to wildfire mitigation and infrastructure upgrades, cheap and plentiful hydropower has so far helped offset those increases.

Southeast and Mid-Atlantic
(Alabama, Arkansas, Delaware, Florida, Georgia, Kentucky, Louisiana, Maryland, Mississippi, North Carolina, South Carolina, Tennessee, Virginia, and West Virginia)

Key factor: Extreme Weather

Southeastern states frequently face hurricanes, flooding, and extreme heat. In recent years, the number of billion-dollar disasters in the region has increased, an ominous sign of the havoc that climate change will wreak. Utilities are fronting the costs of both weathering these events and rebuilding in their aftermath — and then they pass them on to their customers.

The cost of distributing electricity — think the power lines that deliver energy to your home — rose significantly in the Southeast over the past few years, driven mostly by capital expenditures to upgrade and build new infrastructure. In Florida, for instance, damage from Hurricanes Debby, Helene, and Milton in 2024 resulted in residential price increases from 9 to 25 percent the following year. Similarly, Entergy Louisiana’s plan to harden its grid costs a whopping $1.9 billion, much of which will be borne by customers through rate increases.


Some states in the region, such as Virginia, have also seen a major influx of data centers, which consume enormous amounts of electricity. In some areas, utilities are upgrading infrastructure to meet that demand, raising concerns that those costs could push electricity prices higher. However, a national study by Lawrence Berkeley National Laboratory found that an increase in demand in states between 2019 and 2024 actually led to lower electricity prices on average. That’s because when there’s more demand for power, the fixed costs of running a utility — such as maintaining the poles and wires that deliver electricity to your home — are spread out over a greater number of customers, leading to lower individual bills.

In Virginia, the world’s largest data center hub, electricity prices rose only modestly between May 2024 and May 2025, despite a rapid buildout of new facilities. But that dynamic could shift as hyperscalers construct ever-larger campuses. Ultimately, prices will hinge on how utilities and regulators choose to plan and pay for that demand.

For now, however, extreme weather remains one of the region’s main drivers of rising costs.

Southwest and Mountain West
(Arizona, Colorado, New Mexico, Nevada, Utah, Wyoming )

Key factor: Hotter summers

Arizona and New Mexico saw a decrease in retail electricity prices between 2019 and 2024, after adjusting for overall inflation. However, there is a big difference between the states in how much residents pay for energy every month. Energy bills in New Mexico averaged just $90, while in Arizona they were nearly double at $160.

The main difference between the two states comes down to the fact that a greater share of Arizona residents are exposed to scorching summer temperatures — and therefore use more air conditioning, especially in population centers like Phoenix. (Average summer highs in Phoenix are about 20 degrees Fahrenheit higher than they are in Albuquerque, New Mexico’s largest city.) As a result, Arizonans use an additional 400 kWh every month, which leads to higher energy costs.


Arizona residents could also see higher prices in the coming years as a result of rate cases that are being considered, which, if approved, will take effect in 2026. Both Arizona Public Service and Tucson Electric Power are asking the state to approve a 14 percent increase in rates, which could translate to an increase of about $200 in average household energy bills per year. Both utilities have justified the increase by citing the need to modernize the grid as well as higher costs of constructing and maintaining infrastructure.
Texas

Key factor: Regulatory free-for-all

Texas is a land of contrasts. Though it’s an oil-and-gas stronghold, the Lone Star State generates a significant share of its electricity from wind and solar. And unlike most states, it operates its own power grid and runs a deregulated electricity market in which electricity prices can swing sharply from hour to hour.

In Texas, local utilities compete to buy power from generators — natural gas plants, wind farms, and solar arrays among them — in a wholesale market, and then sell that energy to customers. The system gives consumers a lot of choice in picking utility providers, but it also allows utilities to pass on wild swings in the price of power generation. If the cost of natural gas skyrockets during a particularly cold winter when solar is less available, for instance, wholesale electricity prices jump with it. This can lead to eye-popping energy bills, like those seen during 2021’s Winter Storm Uri. The setup ultimately leaves consumers exposed to price shocks, especially when extreme weather hits.

Perhaps as a result, rising electricity costs in Texas are driven by the cost of delivering power — and in particular by swings in natural gas prices, since gas-fired power plants are the state’s primary providers when weather conditions don’t enable wind and solar. While average retail electricity prices fell by a little more than 5 percent between 2019 and 2024, Texans still pay some of the highest energy bills in the country, reflecting surging demand driven by population growth and industrial expansions as well as sharp price spikes during the state’s scorching summers and winter months.

As the state’s population grows, new data centers get built, and more renewable power is brought online, utilities are also having to invest heavily to expand the grid and harden it against extreme weather like Uri, during which at least 246 people died, mostly due to hypothermia. One analysis found that transmission costs grew from $1.5 billion in 2010 to over $5 billion in 2024 and could surpass $12 billion per year by 2033.

Anita Hofschneider contributed reporting to this piece.

This article originally appeared in Grist at https://grist.org/energy/power-bills-electricity-prices-state-by-state/.

Grist is a nonprofit, independent media organization dedicated to telling stories of climate solutions and a just future. Learn more at Grist.org

The Last Stand for King Coal

By Felicity Bradstock - Feb 21, 2026

• The Trump administration has introduced sweeping measures to boost coal production, reduce royalties, and delay plant closures under its “energy dominance” strategy.
• 
  
• Market dynamics - including cheaper natural gas, renewables, and battery storage - have eroded coal’s economic competitiveness.
• 
  
• Decades of plant retirements, shrinking workforce numbers, and global export competition make a sustained U.S. coal revival improbable.
• 
  

United States President Trump has been pushing for a return to fossil fuels, after the Biden administration spent several years increasing the country’s renewable energy capacity. Trump has signed several executive orders since his inauguration last January aimed at reversing the country’s most far-reaching climate policy, the Inflation Reduction Act, while making it easier for fossil fuel companies to increase the production of oil and gas. However, as Trump encourages coal firms to delay closures and continue producing coal, experts speculate that it may be too late for a total U-turn.

In September, officials from the Departments of Energy and the Interior, along with the Environmental Protection Agency (EPA), introduced several policies aimed at reinvigorating coal mining and delaying coal plant closures across the U.S. They said the move reflected the aims of Trump’s “energy dominance” agenda. Interior Secretary Doug Burgum announced the opening of over 13 million acres of public land for coal projects. Wells Griffith from the Department of Energy also unveiled $625 million in funding to increase the U.S. coal fleet, including $350 million to restart or refit existing plants.

Meanwhile, President Trump’s One Big Beautiful Bill Act reduced coal royalties from 12.5 percent to 7 percent, for new and existing leases, aiming to boost mining by making it more profitable. “President Trump promised to put American energy workers first, and today we’re delivering,” Secretary of the Interior Doug Burgum said in September. “By reducing the royalty rate for coal, increasing coal acres available for leasing, and unlocking critical minerals from mine waste, we are strengthening our economy, protecting national security, and ensuring that communities from Montana to Alabama benefit from good-paying jobs. Washington doesn’t build prosperity, American workers and entrepreneurs do, and we’re giving them the tools to succeed,” Burgum added.

The Trump administration has justified its support for coal by saying it will help the U.S. win the “AI arms race” against China. “AI is going to change … every job, every company, every industry,” Burgum stated. “None of that happens without electricity. “We have to have a strong, powerful coal industry — not for five years, not for 10 years. It’s got to be here for decades.”

In January, the EPA announced a proposed rule that would allow 11 coal plants to dump toxic coal ash into unlined pits until 2031, a decade longer than stated in existing federal rules. This could lead to several coal plants – which would otherwise be forced to close under the current rules – to remain open for several more years. These 11 facilities have already exceeded the 2021 deadline to close following an extension introduced during Trump’s first term in office in 2020.

However, many energy experts believe it is simply too late for the United States to make a U-turn on its plans to curb coal production. After several years of demonizing the coal industry for producing the “dirtiest fossil fuel” and significant investment in the expansion of the country’s renewable energy capacity, there are currently no new U.S. coal plants under development.

The rise of cheaper and cleaner alternatives, such as wind energy, has forced a decline in investment in the coal sector in recent years. U.S. utilities are increasingly favouring cleaner energy additions, such as battery storage, gas, and nuclear power to new coal-fired capacity due to the lower cost and greater efficiency of such projects.

In addition, the U.S. coal industry has lost its competitive edge in recent years, with several Asian and Australian coal plant operators now capable of producing much cheaper coal than their U.S. counterparts. This means that U.S. coal producers appear increasingly less attractive to foreign importers. While Asian buyers account for more than half of all U.S. thermal coal shipments, growing this market share would be challenging as alternative exporters, such as Indonesia, now offer faster shipping times at a lower cost.

Around six times more coal power plants have been retired than constructed in the U.S. this century, totalling around 166,000 MW compared to 26,000 MW of capacity, demonstrating the movement away from the fossil fuel. This means that the strong coal workforce that once existed has dwindled in recent decades, from around 91,600 in 2011 to 45,500 in 2023, suggesting that a revival of the industry would need a new generation of workers to be train

ed to support the expansion of a dying industry.

Despite Trump’s many attempts to increase U.S. coal production, the industry does not appear to be biting. While some coal plants may remain open for longer than previously planned, adding new capacity is unlikely to be viewed as economically viable given the falling prices and increasing efficiency of both natural gas and renewable alternatives.

By Felicity Bradstock for Oilprice.com

Trump eases mercury rules for power plants in bid to boost coal

Bloomberg News | February 20, 2026 

Plant Bowen in Georgia, the third largest coal-fired power station in the US. Credit: Wikipedia

The Environmental Protection Agency on Friday rolled back regulations limiting mercury and other toxic air pollution from power plants, the latest in a series of moves by President Donald Trump’s administration designed to boost the nation’s shrinking coal sector.

The 2012 Mercury and Air Toxics Standards for power plants rule — called MATS for short — requires the facilities to reduce emissions of mercury and other metal air pollutants, such as arsenic and lead, which have been linked to heart attacks, cancer and developmental delays in children.

President Joe Biden’s administration strengthened the rule in 2024. Now Trump’s EPA is undoing those changes, claiming that they put an undue burden on coal plants in particular.

“The Biden-Harris administration’s anti-coal regulations sought to regulate out of existence this vital sector of our energy economy,” said EPA Administrator Lee Zeldin. “The Trump EPA knows that we can grow the economy, enhance baseload power, and protect human health and the environment all at the same time.”

Coal- and oil-fired power plants will no longer have to comply with a 2027 deadline set under Biden to install technology on smoke stacks for continuous monitoring of soot, or what’s called filterable particulate matter. A stricter mercury emissions standard for certain coal plants, finalized in 2024, is also being replaced with the original 2012 standard.

Former EPA officials and environmental advocates criticized the rulemaking, saying it gives power plants a pass to pollute more. Ending the requirement for monitoring “means Americans will not be able to see when power plants are violating pollution limits and emitting excessive amounts of cancer-causing pollution,” said John Walke, a senior attorney at the Natural Resources Defense Council who used to work at the EPA.

The Edison Electric Institute, which represents investor-owned US power companies, provided a muted response. “While we are reviewing the final details of this action, we appreciate Administrator Zeldin and his team’s focus on advancing consistent regulatory policies that account for impacts to reliability and customer bills,” said Brian Reil, an EEI spokesperson.

Months before the Trump administration announced its intention to unwind MATS, the EPA encouraged power plant companies to apply for two-year waivers to the Biden-era rules, authorized by Trump. Roughly 70 power plants ultimately received the presidential exemptions.

Since then, the administration has taken many steps to boost the nation’s coal sector, including earmarking more than half a billion dollars to help upgrade existing plants, using emergency powers to keep older facilities from retiring and allowing coal plants to access the Energy Department’s loan program, which has hundreds of billions of dollars in financing authority.

Even so, it’s unclear whether the president’s initiatives will be enough to dramatically shift the domestic landscape for coal, which has declined for years in the face of competition from lower-cost natural gas and renewable power, as well as growing environmental regulations and climate change concerns.

The EPA says the new MATS rule could save $670 million starting in 2028 through 2037. In the final rule, the agency acknowledged that it did not quantify the human health effects resulting from changes in emissions of small particulate matter called PM2.5, nitrogen oxides, or NOx, and volatile organic compounds, or VOCs. The Biden EPA had estimated its strengthened rules would yield $300 million in health benefits and an additional $130 million in climate benefits.

The policy change comes days after the agency scrapped a scientific determination that climate change poses a threat to human health, and with it, greenhouse-gas standards for vehicles.

Since the MATS rule first took effect under President Barack Obama, every subsequent administration has attempted to change it. The EPA during Trump’s first term tried watering it down, and then the Biden administration undid those changes and further strengthened the rule.

Biden EPA officials found that the vast majority of coal plants were not just meeting but exceeding federal standards for toxic soot, said Walke. Because most plants were well below the threshold, the agency decided to lower it, a push that would force a small number of facilities to make new pollution control upgrades to meet the standards, he said.

Similarly, the EPA found power plants that had already adopted continuous monitoring for soot had lower pollution, and required it for all plants going forward.

“If there’s technology that people can use to achieve a certain level of reductions, then that’s what we should expect from everybody, and that’s what people who live all around the country should expect,” said Janet McCabe, who served as EPA deputy administrator under Biden.

With the stricter MATS rules rolled back, she said, a person may be exposed to more pollution than they otherwise would have “because the company they live next to has chosen not to install available cost-effective technology.”

(By Zahra Hirji)