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Last week, the Biden administration announced its final car emission standards, aimed at pushing the auto industry to create more zero-emission vehicles. While there’s plenty in the 1,200-page document for policy wonks, politicians, environmental advocates, and automakers to hem and haw over, there’s at least one thing no one seems too bothered about: The new emissions rules stand to boost plug-in and conventional hybrid sales, thanks in part to some small changes to how their emissions are considered within the mix of an automaker’s fleet.
To recap: The biggest headline change from the proposed rule to the final one is that automakers now have a slower ramp toward reducing their fleet-wide emissions by roughly 50% come 2032. A handful of sensational headlines notwithstanding, the new rules do not mandate that automakers build and sell only EVs. The point is to reduce tailpipe emissions. How automakers go about it is their business.
“Automakers may see it fit to introduce more hybrids and plug-in hybrids, along with some electrics,” Thomas Boylan, regulatory director at the Zero Emissions Transportation Association, told me. “Or if they can find the engineering capacity to create an internal combustion engine that doesn't produce tailpipe emissions, that's a viable pathway to these standards,” he added. That said, how automakers account for the emissions from their fleets — and specifically from hybrids and plug-in hybrids — is not open to interpretation.
When plug-in hybrids are running on battery power, the Environmental Protection Agency counts those as zero-emission miles. Historically, the EPA has assumed that everyone with a PHEV plugs it in every day and is therefore maximizing its battery-powered mileage, however more recent studies have shown that is probably not actually the case.
“There's some mixed data out there in terms of how frequently people who own these [PHEV] vehicles plug them in, and that's a big factor in how much compliance they should get,” Chris Harto, the senior policy analyst for transportation and energy at Consumer Reports, told me.
“How much compliance they should get” became a key question in how the new car emissions standards would account for PHEVs. The draft rule issued last year had proposed reducing the amount of compliance credit automakers would get for plug-ins starting in model year 2027 to account for the discrepancy in battery miles traveled. But the final rule delayed that phase-in until model year 2031, in order “to provide additional stability for the program, and to give manufacturers ample time to transition to the new compliance calculation.”
Hybrid and PHEV vehicle sales have been surprisingly robust over the past few years, as Jesse Jenkins pointed out on Heatmap’s Shift Key podcast. Hybrid electric sales were about on par with battery electric sales in 2023, at around 1.1 million vehicles each, Jenkins said, which is “way higher than what we expected.”
As of February, plug-in and traditional hybrid sales were growing five times faster than EV sales, Morgan Stanley reported. The Argonne National Laboratory also found that during the same month, PHEV and hybrid sales rose to more than 130,000 all together. To put that in perspective, last year's record EV sales alone averaged just about 100,000 per month across all brands. These robust sales numbers, combined with the new EPA tailpipe emission rules, could continue to drive growth in hybrid and PHEV sales, even as EV sales growth cools.
“I think a lot of automakers underappreciated the big bump in hybrid sales that many people have rightly celebrated in 2023. That huge jump in hybrid sales coincides directly with a huge jump in EPA emission standards from 2022 to 2023,” Harto told me. In 2021, the Biden administration revised a Trump-era rule that sought to weaken vehicle emission standards. Those revised rules, which took effect for the 2023 model year, were 10% tighter than the year prior.
“These standards have a history of pushing automakers to deliver vehicles that save consumers money on fuel,” Harto said. “I don't think we would have seen the jump in hybrid sales that we saw last year without the jump in emission standards in 2023.”
Still, he noted, “The more hybrids (or other gasoline efficiency improvements) and PHEVs automakers build, the fewer BEVs they will have to build to comply.”
This will likely slow the EV adoption curve, but if it leads to more and cheaper plug-in hybrids than we would have had otherwise, it could help U.S. consumers get more comfortable with the idea of plugging in rather than filling up their cars.
“I think the final rule reflects more of an understanding that there will be more hybrid electric vehicle penetration rates over the next few years,” Boylan told me. While the true cost and emissions savings are in fully battery electric vehicles, it might take consumers a minute to get there. “I think, ultimately, a PHEV offers an opportunity to educate a consumer on what an electric vehicle might be able to do to meet their personal needs, and that creates a pathway to a true BEV purchase, on the next vehicle.”
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The cost impacts can be felt for years.
In an era of extreme weather, infrastructure repair and hardening charges are piling up for utilities — and for ratepayers. Utilities in at least 18 U.S. states are now passing on disaster-related charges in electricity bills, according to data from Heatmap and MIT’s new Electricity Price Hub. And as extreme weather continues apace with climate change, those costs will only get higher.
Though California and Florida remain the expected outliers, the disaster recovery pattern is decidedly national, spanning the Pacific Northwest, Midwest, Southeast, and Appalachia, with 36 utilities having introduced at least one specific disaster-related charge since 2020. Often, such charges are tacked on years after the disaster they’re intended to address, and they sometimes begin at such a low cost as to be almost invisible to customers before ratcheting up.
Compared with generation, transmission, and distribution costs, disaster recovery charges are frequently a small line item on bills. For DTE customers in Detroit — where powerful windstorms can knock out power for days — a base securitization charge associated with tree trimming (and the retirement of the River Rouge coal plant) has increased by just over a tenth of a cent per kilowatt-hour since 2022. That’s compared to about three pennies per kilowatt-hour for all the other DTE rate increases over the same period, combined.
Starting last year, customers of Kentucky Power Co. have likewise been paid three securitized surcharge riders, totaling about $0.01 per kilowatt-hour, to help cover $78.8 million in “deferred storm costs” related to major storms that hit the state every year between 2020 and 2023. That’s about $12 added to the average Kentucky Power Co customer’s bill, or an increase of roughly 6%.
Securitization is one method utilities use to deal with debt incurred due to extreme weather. Such plans allow utilities to issue long-term low-interest bonds to cover disaster-related costs upfront, avoiding shorter-term loans and the sticker shock of a large rate jump for ratepayers. In the case of Kentucky Power, securitization allowed the utility to avoid what would have been a 13.1% rate increase, per the Kentucky Public Service Commission.
Because securitization charges are tied to bond payments and are periodically adjusted, our data shows the associated disaster recovery charge for Kentucky Power has dropped slightly since it was introduced in 2025. The downside to securitization, though, is that — as, again, in the case of Kentucky Power — ratepayers will be footing the costs of the 2020-23 storm seasons for a long time: more than two decades. And while the cost per bill might be small now, by the time the 20-year recovery period is up, there will almost certainly have been further damaging storms in the state. Those costs accumulate.
The process of securitization also requires legislative approval from the state and the blessing of the local regulator. For lower and more routine damage, weatherization, and emergency operating costs, utilities can use a faster-acting rider instead.
Riders, however, can ramp up once storm costs are tallied. Oklahoma Gas & Electric’s storm cost recovery rider, for example, started at just $0.000739 per kilowatt-hour in 2020, our first year of data, and has since ballooned by 460%.
While that amounts to only about $4 to $5 a month on the average customer’s $136 electricity bill, in states like California and Florida, cost recovery can be much higher. Tampa Electric customers are in the midst of an 18-month payment plan to cover $464 million in restoration costs from Hurricanes Helene and Milton in 2024, or about a $22 increase in the average customer’s monthly bill. That’s in addition to the utility’s Storm Protection Plan, which began in 2020 and funds grid-hardening measures such as undergrounding power lines, and runs about $8 per month for the average customer — or a combined $360 per year.
FPL Northwest Florida — formerly Gulf Power, serving northwestern Florida — has a $385 million storm protection plan to harden its grid. That cost is reflected in a 2,589% increase in the utility’s “Storm Protection Plan Cost Recovery” charge since 2021, due to the cascading costs of hurricanes. Duke Energy Florida’s storm protection plan charge is up almost 3,000% since it was introduced in 2021, also related to infrastructure hardening.
But hurricanes are also a problem in Louisiana, where smaller rural co-ops don’t have the same access to financing as large investor-owned utilities. Six Louisiana electric cooperatives in our database have added disaster-related riders since 2021: Jefferson Davis Elec Coop, Inc, as a reactive measure to address the costs of the 2020 hurricane season; South Louisiana Electric Coop and Southwest Louisiana EMC with riders in 2022 to help with recovery from Hurricane Ida and others in 2021; and Pointe Coupee Elec Member Corp, Claiborne Electric Coop Inc, and Concordia Electric Coop, Inc, all with emergency reserve fund riders added in 2025.
“Tornadoes, straight-line winds, tropical storms, ice storms, and even the occasional hurricane can cause millions of dollars in damage in a single day,” Claiborne wrote to its customers to justify the increase last year. “As much as we wish we could control the weather and keep storms at bay, we know future harmful storms are inevitable.” (All six co-ops have also seen their total rates increase between 2021 and the latest available data, with Claiborne rising by almost 38%.)
Many West Coast utilities are also bracing for a future full of extreme weather-related disasters. Washington State’s Puget Sound Energy has added a surcharge of about $14 per year to electricity customers to recover the costs from its forward-looking Wildfire Mitigation and Response Plan. PacifiCorp and Portland General Electric Co., both in Oregon, are likewise passing fire-related mitigation costs, such as vegetation management, onto their customers. For California’s PG&E, wildfire-related charges accounted for roughly 18% of system costs in the five years preceding 2023, though those charges are also rolled into distribution costs and aren’t always clearly itemized.
Due in part to regulatory lag, the impacts of major storms such as the 2024 hurricanes that affected Tampa often aren’t felt by ratepayers for years. As the Electricity Price Hub data shows, increases in disaster recovery-related rate charges don’t neatly map to major disaster years, or even necessarily to the years immediately following them. Due in part to legal mechanics, customers in Kansas only started to see the passed-on costs of elevated natural gas prices from the 2021 Winter Storm Uri on their 2023 bills.
It is also not uncommon for costs to start so low they’re almost unnoticeable to customers before growing in scale. Alabama Power’s Natural Disaster Reserve started at a mere $0.000645 per kilowatt-hour in 2020, but has risen 155% to $0.001642 per kilowatt-hour. While that still represents only a handful of dollars per month on the average customer’s $261 monthly bill, it shows that disaster charges that slip onto bills might not stay “invisible” forever.
One major limitation of our data: Utilities don’t always neatly identify riders and surcharges related to storms and extreme weather, and costs might also be rolled into distribution and transmission base rates. After a hurricane, for example, a utility might include grid-hardening costs as capital expenditures, passing them on to customers as increased distribution costs related to infrastructure, rather than flagging them as specific “disaster” charges. This means that disaster surcharges visible in the data, including those cited in this article, should be taken as bare minima.
Temporary riders can also be replaced — as in the case of Entergy Mississippi’s SD-9 rider, which dated back to Hurricane Katrina and addressed “extraordinary incremental storm damage costs,” which appears to zero out in our data. In fact, it was followed up by a 2024 storm damage mitigation and restoration rider aimed at creating a fund to absorb the shocks of “windstorms, ice storms, thunderstorms, tornadoes, hurricanes, floods, wildfires, or other such events.” The 2024 rider is nearly three times as high as the one it replaced.
In other words, while we’ve been able to single out 58 specific charges that utilities have identified as either addressing or anticipating extreme weather-related disasters since 2020, that is almost certainly an undercount. While still being illustrative, the data also points to an even bigger takeaway: This is just the tip of the iceberg. The true cost to ratepayers — and the extent of weather-related impacts on electricity bills around the country — will be much larger.
That means more electrification, more stockpiling, and more coal.
Much of the world — or at least much of Asia — seems to be responding to the energy stress caused by the Iran War by attempting to reshape itself in China’s image.
The oil, refined products, and natural gas that is supposed to be flowing through the Strait of Hormuz was largely destined for Asian countries, which are now learning a harsh lesson in the dangers of foreign fossil fuel dependence.
One country whose economy has been relatively resilient to the crisis, however, is China.
That’s despite the fact that China is the world’s second-largest consumer of oil (and its largest importer) and its third-largest consumer of gas (and largest consumer of liquified natural gas). But it has not seen the same type of immediate crisis that other Asian energy importers have. It may be the No. 1 customer of oil coming through the Strait of Hormuz (and especially Iranian oil, which is still flowing), but its main policy adjustment the government has made since the United States and Israeli attack has been to limit exports of refined products. It also came into the crisis with stockpiles of oil estimated at 1.4 billion barrels, more than three times the amount of oil the International Energy Agency coordinated the release of.
In the short run, many Asian countries, especially poorer ones, are embracing energy use restrictions, including limitations on driving and raising temperatures in government buildings, while some richer countries are able to increase supply by rebooting nuclear plants and upping capacity limitations on coal-fired power plants.
In the longer run, several countries are making investments in energy sources that are less dependent on imported fossil fuels. In Vietnam, the developer behind a planned liquified natural gas project asked the government to allow it to instead build a solar and batteries project. The Southeast Asian nation also inked a deal with Russia to work on its first nuclear power project.
There’s also early data of bottom up as well as top down embracing of electrification, with exports from Chinese EV juggernaut BYD increasing and “bustling showrooms across Asia,” Bloomberg News reported.
This has largely been China’s playbook. China’s energy policy has seen huge pushes in electrification, renewables, and clean energy, both at home (38% of its electricity comes from clean sources, and it’s responsible for more than half of world solar and wind capacity additions) and abroad, where China is the leading supplier of solar panels, batteries, and electric vehicles, and has made deliberate efforts to dominate global supply of clean energy technology through exports.
But the country is not pursuing a crash decarbonization policy in order to bring emissions down as fast as possible, in line with global targets. Instead, as Heatmap’s Robinson Meyer and Lauri Myllyvirta of the Centre for Research on Energy and Clean Air explained on a recent episode of Shift Key, China’s energy policy is based around several goals, some of which line up with decarbonization, and some of which don’t.
The first is energy security, and specifically mitigating dependence on seaborne imports of fossil fuels, which can mean both stockpiling oil and embracing renewables. The second is domestic air quality, which means strict particulate pollution policies, moving heavy industry closer to power sources in the south and west of the country and away from large cities in the east, and seeking to replace coal home heating with natural gas. And the third, as Myllyvirta put it, is “wanting to make sure that China has technological leadership [and] market leadership” in the energy technologies of the future, which can explain the industrial policy efforts around solar, batteries, and electric vehicles and their development into world-leading export industries.
This is also an approach to energy policy that’s perfectly consistent with burning and buying a lot of fossil fuels, as many Asian countries are looking to do today, with coal utilization going up as countries scramble to find new sources of imported natural gas.
Several energy analysts have forecasted that China’s experience of the Iran crisis will lead to increased stockpiling worldwide, and thus become a new source of incremental demand for oil, even if global demand for oil in transportation plateaus or falls.
“Countries that have been building their strategic storage — most notably China — look prescient today. Others may respond by starting to do the same,” a team of Morgan Stanley analysts wrote in a note to clients in the early weeks of the Hormuz crisis. “On paper, that is ‘inventory building.’ In practice, it behaves like incremental demand: persistent buying on dips, greater willingness to pay for security of supply, and a higher floor under the price distribution than we assumed before the Strait went quiet.”
And you can’t build stockpiles of oil to cushion disruptions to global trade without buying the oil in the first place. Those stockpiles presume that your economy maintains some base-level dependence on oil, which has become increasingly undesirable of late. China is also investing heavily in the coal-to-chemical sector, using coal as a feedstock for petrochemicals instead of oil or natural gas, which is carbon-intensive in the extreme.
Other countries are looking in the short run to increase coal output. While China has a largely domestic supply of coal, there are fewer bottlenecks for seaborne coal like the Strait of Hormuz for oil, as the former is available at scale from several countries (Indonesia, South Africa, Australia) that are not stuck behind a narrow and geopolitically volatile strait.
The other short-term lever some Asian countries can pull is nuclear power. Taiwan is looking to restart nuclear plants that it shut down last year, while several Southeast Asian countries had already made plans to build up their nuclear power resources. And earlier this week, Sri Lanka announced plans to rush forward a solar and batteries project and to look abroad for funding for a hydroelectricity project.
To the extent that any of these countries now experiencing energy hardship may be able to imitate the Chinese model, it will come at a substantial cost, not just in building up stockpiles that may go unused or infrastructure projects that are abandoned, but in closer links — and even dependency on outside sources for energy technology, cars, and critical minerals — on a rising regional hegemon instead of the vagaries of the world oil and gas market.
Countries may try to become more Chinese, but to China, they may just be customers.
Current conditions: Repeated rounds of storms will dump up to 4 inches of rain from Texas to the Great Lakes • Jerusalem, where Passover just began for Jews, is wrapping up a rain storm, with sunny skies and roughly 65-degree Fahrenheit weather predicted throughout the duration of the eight-day holiday • A Saharan dust storm is turning the sky over parts of Greece an eerie orange and red.
At 6:35 p.m. ET last night, I watched my daughter reach her hand up at the image on our television of one of the most powerful rockets the United States has ever launched, carrying America’s first lunar crew in half a century. Looking at her stare up in wonder, I prayed that the greatest achievements of our civilization lie ahead of us, forged not of zero-sum contests between adversaries but peaceful competition among rivals. Parenthood makes it difficult not to think in such dramatic terms. But there’s the fact, too, that this successful launch puts us one step closer to something extraordinary: A nuclear power plant on the moon. As I told you back in January, the Department of Energy set a goal of installing a nuclear reactor on the moon in the next four years. The mission will slingshot the crew of four astronauts — commander Reid Wiseman, pilot Victor Glover, mission specialist Christina Koch, and Canadian Space Agency astronaut Jeremy Hansen — around the moon and back to Earth. The subsequent two U.S. launches — Artemis IV and V, which are scheduled for 2028 — will bring crews to the lunar surface. “This time, the goal is not flags and footprints,” NASA Administrator Jared Isaacman said last week, according to E&E News. “This time, the goal is to stay.” NASA aims to have a nuclear reactor ready to make the journey to the moon by the end of the decade.
One of the country’s leading next-generation nuclear developers is also stepping up its ambition. Executives from TerraPower, the Bill Gates-backed sodium reactor startup, held talks with the utility Evergy about a potential power plant in Kansas this week. “We’re not ready to announce any sites. Multiple communities in Kansas have kind of raised their hand and said they’re willing to host a Natrium power plant,” TerraPower CEO Chris Levesque told Fox4 Kansas City.
Japan is turning its nuclear reactors back on, looking at building wind turbines, and relaxing rules on coal-fired stations to bolster its electricity supply as the Iran War halts the flow of liquified natural gas through the Strait of Hormuz. But the country invested a lot in LNG infrastructure as the fuel replaced atomic energy following the shutdowns triggered by the 2011 Fukushima disaster. So it’s also looking for new supplies. The Japan Organization for Metals and Energy Security, a government-owned investor, launched a new initiative Wednesday to offer a return on LNG investments. The industry is already abuzz. In just the past week, at least two Japanese companies have made big LNG investments.
On Wednesday night, three hours after the rocket launch, President Donald Trump gave a televised speech highlighting what he described as U.S. achievements in the Iran War and setting the stage for the conflict to wind down. But he offered no specific timelines, and oil prices rose steadily throughout the speech.

U.S. coal exports fell in 2025 for the first time in four years as overseas sales of thermal coal dropped by 18% and metallurgical coal by 11%. If you thought this could be a sign of Trump’s coal revival taking hold, think again. The plunge, according to the Energy Information Administration’s latest report, “largely reflects a 92% decrease in exports to China in 2025 compared with 2024, after China imposed a 15% additional tariff on imports of U.S. coal in February of last year and 34% reciprocal tariff on imports from the United States in April.”

U.S. production of crude, on the other hand, surged by 3%, or 350,000 barrels per day, in 2025. That set a new annual record of 13.6 million barrels per day, the EIA found in a separate analysis. If that’s “drill, baby, drill” in action, then the catchphrase deserves an asterisk indicating that the drilling is taking place in the same locations as before. The number of active rigs per month in the lower 48 states was 5% less than in 2024, and 1% fewer wells were drilled. But efficiency improvements at existing wells resulted in an increase of crude.
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In November 2023, the nation’s leading effort to deploy new small modular reactors, developer NuScale’s project supplying electricity to the Utah Associated Municipal Power Systems, collapsed as inflation sent costs soaring. Oregon-based NuScale, as I have reported for Heatmap, has struggled to make major progress since. Now a report released this week by the Energy Department’s inspector general has determined that the Office of Nuclear Energy “did not effectively manage the project.” In total, the project wasted about $183 million in federal funding “without key results,” including $143.5 million that the Office of Nuclear Energy gave to NuScale up front without any serious oversight or conditions.
Last month, I told you about GE Vernova and the Japanese company IHI running tests to see whether a gas turbine could run on ammonia, the green version of which is made without producing carbon emissions. If that could work, green ammonia could offer a way to eliminate emissions from gas plants without rendering relatively new turbines suddenly worthless. But green ammonia has traditionally cost much more than the natural gas-based gray ammonia. Not anymore, at least not in Asia. The price of green ammonia is now cheaper than that of gray ammonia due to the ongoing conflict in Iran, Hydrogen Insight reported.
How’s this for a cursed AI prompt: Remake Frank Sinatra’s “The Coffee Song” but make it about rare earths. The U.S. just secured a deal with Brazil to give $565 million in a loan from the U.S. International Development Finance Corporation to produce rare earths at Serra Verde’s mine. The move comes right after the U.S. managed to snatch up one of the few Congolese cobalt miners that China didn’t already control.