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There isn’t one EV transition. There are two.

This has not been a good week for the electric-vehicle transition. On Wednesday, General Motors scrapped a self-imposed plan of building 400,000 electric vehicles by the middle of next year. Then it jettisoned plans with Honda to build a sub-$30,000 EV. On Thursday, Mercedes Benz announced that its profits had fallen in part due to turbulence in the EV market, and Hertz ditched a plan to have EVs make up 25% of its fleet by 2024.
Nor has the past month been much better. Ford has slowed down its EV factory build-out. Elon Musk announced that Tesla was taking a wait-and-see approach to opening its next plant, in Mexico, and The Wall Street Journal has reported that EV demand is proving weaker than once expected. Higher interest rates and, perhaps, a continued lack of public chargers now seem to be impairing the EV transition.
It’s an odd time, because while the day-to-day news is bad, the overall trend remains good — surprisingly good, even. More than 1 million EVs have been sold in America this year, and the country is likely to record 50% year-over-year EV market growth for two years in a row. That is not the usual sign of an industry in trouble. The industry is faltering, yes, but only compared to the rapid scale-up that companies once aimed for — and that the Paris Agreement’s climate targets demand. And at a global level, the news is better: The economics of batteries and trends in the Chinese and European markets leave little doubt that EVs will eventually win.
So how to make sense of this moment? Automakers, it seems, are not doubting whether the EV transition will happen; they are pausing to figure out how best to proceed. Journalists often talk about the “EV transition,” but this is something of a misnomer — there are really at least two different transitions, two different bridges to the EV future.
One of those transitions must be navigated by the legacy automakers, such as Ford and GM. The other must be completed by the new electric-only upstarts, such as Tesla and Rivian. Both transitions are, today, half-complete. What is notable about this moment is that both transitions are also in flux — and the companies and executives tasked with navigating them are struggling with their next steps.
The first bridge must be built by Ford, GM, Toyota, Volkswagen, and every other legacy automaker heavily invested in the U.S. market. You can think of it as a bridge made of cross-subsidies — subsidies not from the government, but from other cars in their product line.
Right now, many automakers earn their biggest profits by selling big, gas-burning vehicles: crossovers, SUVs, and pickup trucks. They lose money, meanwhile, on each EV that they sell. So over the next few years, these companies must take the huge profits from their SUV-and-truck business and reinvest them into scaling up their EV business.
You can see how difficult this will be by looking at Ford, which conveniently reports earnings from its internal combustion business separately from its electric vehicle business. During the first half of 2023, Ford’s global gas and hybrid sales earned $4.9 billion before interest or taxes. Ford’s EV business, meanwhile, lost $1.8 billion before interest or taxes.
During this same period, Ford sold nearly half a million trucks and SUVs in the U.S. alone, and roughly 25,000 electric vehicles. By one calculation, Ford lost $60,000 for every EV that it sold during the first quarter of this year.
This is the narrow bridge that Ford and its ilk must walk: They must remain mature businesses, delivering consistent profits to shareholders, even as they overhaul their entire product line and manufacturing system. And while these legacy automakers have certain advantages — brand cachet, a network of dealerships, and an understanding of how to make car bodies — they lack the deep familiarity with software or battery chemistries that underpin the EV business. What’s more, their current business rests on uneasy foundations: Because their profits are so heavily concentrated in just a few SUVs and trucks, a sudden shift in consumer tastes, fuel prices, or regulation could undercut their whole hustle.
We’ve already seen one consequence of this concentration in the United Autoworkers strike. By focusing its strikes on just a few factories at first, and then gradually expanding them to include each company’s most profitable facilities, the UAW was able to make its strike fund go further than outside commentators initially estimated. That strategy resulted in record high pay raises for workers in the UAW’s tentative deal with Ford; strikes continue at GM and Stellantis.
But this is, of course, only the first bridge to the EV future. Other companies — including Tesla, Rivian, and the early-stage EV startups Canoo and Fisker — have to build a different path across the river. You can think of this as the bridge of scaling up, although some auto-industry analysts give it a different name: crossing the EV valley of death.
These companies have to survive long enough to build up economies of scale. You can think of it this way: At the beginning of an EV company’s lifespan, it knows very little about how to mass-produce its EVs, but it has a lot of cash to burn. As it matures, it gets better at making EVs and grows its customer base, and it makes cars more frequently and more cheaply. Eventually, it reaches a point where it can sell lots of EVs for more money than they cost to make — that is, it can be a mature, profitable business.
But in the middle, it faces a hold-your-breath moment where its high costs can overwhelm its meager production. This is the valley of death, “the challenging period between developing a product and large-scale production, when a company isn’t earning much if any revenue, but operating and capital costs are high,” as the journalist Steve Levine puts it at The Information.
Nearly every EV company faces this problem to some extent right now. Elon Musk discussed it during a recent rambling Tesla earnings call. “People do not understand what is truly hard. That’s why I say prototypes are easy. Production is hard,” he said. “Going from a prototype to volume production is like 10,000% harder… than to make the prototype in the first place.”
Now, Tesla seems to have mostly cleared the valley of death with its Model 3 and Model Y this year, allowing it to undertake a campaign of aggressive price cuts that have increased demand while retaining some profitability.
But what Musk was talking about — and what Tesla is clearly struggling with — is the Cybertruck, which will debut next month after a multi-year delay. Musk warned that the company had “dug its own grave” by trying to build the Cybertruck and that there would be “enormous challenges” in producing it profitably and at scale.
But “this is simply normal,” he added. “When you've got a product with a lot of new technology or any brand-new vehicle program, but especially one that is as different and advanced as the Cybertruck, you will have problems proportionate to how many new things you're trying to solve at scale.”
Every other EV company finds itself on the same narrow bridge. Rivian, for instance, is somewhere further behind Tesla in general but is fast making up ground. It scaled up its production of its R1T and R1S models last quarter faster than analysts thought, but was at last report still losing money on each vehicle. Rivian’s CEO, R.J. Scaringe, told me that the company is focusing on making its next line of vehicles, the R2 series, easier and simpler to manufacture to avoid this problem.
Even further behind Rivian are Fisker, which claims to have delivered 5,000 of its Ocean SUVs, and Canoo, which is struggling to stay solvent.
What’s hard about this moment, then, is that the downsides and risks of each approach have never been clearer.
If a legacy company completes its EV transition too quickly, then it risks finding itself with a fleet of electric vehicles that the public isn’t ready to buy. Companies like Ford, GM, Volkswagen, and Toyota must scale up a profitable EV product line at the same time that they sell vehicles from their legacy business.
Worldwide, no historic automaker has transitioned fully to making battery-electric vehicles, although some have come very close: BYD, the Chinese automaker that has surpassed Tesla as the world’s biggest producer of EVs, opted to quit making internal-combustion vehicles last year, but it still sells plug-in hybrids. Volvo, too, is making an attempt: It has promised to stop selling internal-combustion cars by 2030. But Volvo is owned by the Chinese automaker Geely, meaning that both of these companies can sell their cars to a much larger and more EV-interested Chinese domestic market.
Yet the second transition is tough, too. Although it may seem that EV-only companies have a lot of freedom (by lacking a network of EV-skeptical dealerships, for instance), they also have no alternative revenue to cushion themselves through a period of soft demand — they can’t ever cross-subsidize. Although it sold buses and not private vehicles, the American EV-only vehicle maker Proterra is indicative here: It went bankrupt earlier this year after getting stuck halfway through the valley of death.
America is going to have a domestic EV industry. By the mid-2030s, most automakers will be integrated EV companies, building and selling electric vehicles that include some in-house hardware, software, and battery components. Consumers will think of their new vehicles more as technology than as a simple mode of transportation, and they will power them from ubiquitous charging stations, which will be as mundane and abundant as wall outlets are today.
That future is certain. But what kinds of cars will we be driving, and what companies will count themselves among the electric elect? I couldn’t tell you. It will all depend on what happens next — on who makes it across the narrow bridge.
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Many nonprofits representing the environmental and climate movement are split.
This is Heatmap Daily, an evening digest written by our executive editor.
It’s now been just over a week since a gang of four bipartisan senators released the Bipartisan American Affordability and Jobs Act, or BAAJA. The permitting reform proposal would make too many changes to federal law to summarize cleanly here — read our explainer for that — but suffice it to say it creates a messy group of winners and losers. Utilities, data centers, and the Trump administration would lose; electricity ratepayers, clean energy companies, long-distance transmission lines, and natural gas pipeline builders win. (As would geothermal startups, virtual power plant providers, and a few other climate tech subsectors that my colleague Katie Brigham recently detailed.)
In the ensuing week since its release, we’ve gotten a better sense of the battle lines over the bill. The hardhat unions largely support the proposal (although the International Brotherhood of Electrical Workers, which is often aligned with utility executives, has stayed notably silent on it.) Clean energy trade groups, such as the American Clean Power Association, back it, too, as do fossil fuel lobbying groups, such as the American Petroleum Institute.
Groups representing the environmental and climate movement are more split, and some of the most influential nonprofits have yet to render a verdict. Earlier today, the Sierra Club published its first take on the proposal, which it described as a “hard look” at the bill. The Natural Resources Defense Council asked its own “hard questions” last Friday. Neither document rejects the proposal outright, although both are critical, and both suggest that future statements are coming.
To some degree, the statements say what you might expect: The groups like all the parts of the compromise that Democrats fought for (such as those that will encourage transmission) and dislike what Republicans wanted (such as those that will ease some pipeline permitting). That is what a compromise means — and for congressional procedure reasons too tedious to explain here, permitting reform will likely always need to be passed as a bipartisan compromise, because it will always need to overcome a 60-vote Senate filibuster.
The Sierra Club’s assessment divides the bill into “green flags,” which will make “long-overdue changes to protect consumers and level the playing field for proposed transmission,” such as by making it easier to plan long-distance power lines, protect ratepayers from utility and data center freeloading, and clarify who in the government can approve power lines. It also names four “red flags,” including the “hollowing out” of court authority over some permits, the removal of a Clean Water Act provision that lets governors block pipelines and power lines, and the option to delegate partial Endangered Species Act enforcement to state governments.
This is a helpful scheme, and I hope the Sierra Club continues using it. But I think it would be a mistake to analyze the bill solely through this metric, because it implicitly assumes we are starting from a neutral baseline — or that every additional “unit” of policy support, so to speak, helps an insurgent industry as much as it might aid an incumbent industry. To be clear: Although I’ve endorsed the idea of permitting reform in the past, I’ve been careful not to endorse or reject this particular permitting bill yet; I hope to write a more comprehensive take on this legislation — and whether I think it’s a good idea — before senators ultimately vote on it.
So for now, let me say that I think everyone should keep in mind that the baseline around U.S. energy permitting is, in fact, not neutral today. By this, I do not merely mean that natural gas pipelines already have a one-stop shop for federal permits, but transmission developers have to go hat in hand to every state government; nor that fracking is already carved out from some federal environmental review laws, but enhanced geothermal technology isn’t.
The mismatch goes deeper than that. Many of the discussions of the bill that I’ve seen seem to fear that the United States might witness some enormous and unprecedented fossil fuel buildout were the bill to pass. But make no mistake: We are already witnessing such a buildout. The United States is slated to add more than 60 gigawatts of new natural gas generation capacity by 2030 under its existing laws.
The existing system of laws, regulations, and procedures is failing to avert an enormous fossil fuel buildout. The existing system has proven itself completely inadequate to manage an era of electricity demand growth and the data center boom without surging fossil demand and sky-rocketing electricity prices. The existing system of laws is pushing hyperscalers and developers to burn natural gas on site, often through rudimentary jet engines.
And the existing system of laws has shown that fossil fuel consumers will go to great lengths to move and obtain fossil fuels, even when dedicated transport options like pipelines are not available. I’ve heard fears that the permitting bill will make it easier to build natural gas pipelines. But pipelines, to a dedicated artificial intelligence customer, are no constraint: Oracle is now delivering natural gas to some of its data centers by truck when pipeline capacity isn’t available.
There may be reasons for green groups to reject this deal. (And there may be reasons for Democratic lawmakers to support it anyway, even if environmental groups oppose it.) But the perfection of our current environmental and energy legal regime is not one of them. Even if your sole goal were to reduce the carbon emissions produced by the American energy system — even if you set aside the problems with cost, conventional pollution, or monopoly control — the current system sucks.
Advanced nuclear will take a decade or more to hit commercial scale. Meanwhile, the hyperscalers need power now. Enter the uprate.
When America’s tech titans started plowing money into nuclear technology to power data centers in 2024, companies such as Google and Amazon opted to invest first in next-generation reactor startups. But electricity demand is soaring today, and those projects are still years away — at least — from generating power at reasonable commercial rates.
So the industry is hedging by betting on existing nuclear plants to pump out more electricity in the near term. Uprates — renovations that allow nuclear operators to produce more power from existing reactors — are all the rage this year.
In February, the Department of Energy issued its largest-ever loan to Southern Company to fund up to 6 gigawatts of uprates across the utility’s nuclear fleet. Last week, Amazon signed a deal with Constellation Energy, the nation’s largest operator of nuclear reactors, to uprate the Calvert Cliffs plant in Maryland to generate another 190 megawatts on top of its current 1.8-gigawatt output. Soon after, the Energy Department offered nuclear operator Vistra a $4 billion loan to uprate plants in Ohio and Pennsylvania.
Then on Tuesday, Google inked its own deal with Constellation aimed at wringing out 890 megawatts of new power from 11 reactors across PJM Interconnection, the nation’s second-biggest and arguably most overworked grid system.
“Everyone loves nuclear, but it takes a really long time to build,” Raiford Smith, Google’s head of power and energy for the cloud, told me yesterday. “The fastest way to get it is via uprates. It’s real megawatts, but the quicker, shorter-term approach.”
Building new reactors, he said, “is the intermediate term plan, and we see fusion as the longer term bet.” Given that “new data centers are coming on at a gigawatt a clip, that means even with all the uprates, there’s still more to come,” he added.
The investments into existing nuclear stations deliver a win for Constellation, whose chief executive, Joe Dominguez, has been among the more vocal C-suite skeptics of what my colleague Matthew Zeitlin described as utility executives’ “load growth mania” over the past two years. But the deals say as much about the shifting lines in the debate over how to expand the nuclear power fleet in this country — what size reactors are better, how to finance projects — as the disagreement over how much new generation is needed to supply the artificial intelligence boom.
The deal “is a win-win,” Emmet Penney, the director of energy and infrastructure at the think tank Foundation for American Innovation, told me. “Constellation and Google are revealing just how essential our nuclear fleet is to maintaining our energy dominance.”
America’s last attempt at a nuclear buildout ended in a series of financial boondoggles. The problems traced back to numerous factors: Decades without any nuclear construction atrophied the workforce. Electricity market reforms aimed at breaking up monopoly utilities left the industry with few players equipped with large enough balance sheets to take on megaprojects that would take years to build and billions of dollars of upfront capital. Increased competition from cheap natural gas.
The only two new reactors that made it over the finish line, Southern’s pair of Westinghouse AP1000s at the Alvin W. Vogtle Generating Station in eastern Georgia, came in billions of dollars over budget, in part because the developers erred in choosing a Nuclear Regulatory Commission licensing pathway that required long stops and costly delays every time the builders tweaked the design. Since those were the first AP1000s constructed in the U.S., there were plenty of last-minute design kinks to iron out.
In the meantime, the industry rallied behind the idea of small modular reactors. By making individual reactors roughly a third or less powerful than large-scale units such as the AP1000, the thinking went, developers would need to buy more, helping the technology slide down the cost curve through repeated construction and assembly-line manufacturing of components.
While Google and Amazon both backed fourth-generation startups whose designs use coolants other than water, such as liquid sodium or helium gas, the only such reactor operating in the world is in China, and America’s track record of running similar plants is poor. As such, government-owned utilities such as Canada’s Ontario Power Generation and America’s Tennessee Valley Authority have thrown their weight behind third-generation SMRs that essentially just shrink down existing water-cooled technology. The first of GE Vernova Hitachi Nuclear Energy’s BWRX-300s, a 300-megawatt design based on the boiling water reactors that make up about a third of the U.S. fleet, is now underway at OPG’s Darlington plant. In the U.S., meanwhile, the NRC just issued a construction license for the TVA’s first BRWX-300.
But the completion of the second AP1000 at Plant Vogtle demonstrated an uncomfortable reality proposed by researchers at the Massachusetts Institute of Technology: That the next, cheapest reactor to build in the U.S. would be another of Westinghouse’s flagship design. Vogtle Unit 4 came online in 2024 roughly 30% cheaper and faster than its slightly older twin, Vogtle Unit 3.
If that reduction seemed to justify the approach SMR companies were pursuing, a report by an economist and former antinuclear researcher raises new questions. The study by Charles Komanoff, which I covered here last month, suggests that the number of reactors required to achieve major cost reduction through “economies of duplication” pales in comparison to the price drop achieved through “economies of scale.” In other words, the nuclear industry’s time-tested approach to making reactors more economical — making them bigger — is still the best bet.
The Trump administration certainly agrees. The Energy Department laid plans for at least 10 new AP1000s last year, and put up another nearly $20 billion loan package for utilities that form joint ventures with Westinghouse to build one of the 1,100-megawatt reactors. South Korea is currently working out the fine print on a deal to help finance and build as many as six AP1000s and two APR1400s, the Korean rival to the Westinghouse reactor.
Whether any American utilities step up to help build any of those AP1000s remains an open question.
“There’s no way any utilities could consider building a large AP1000 because doing so could bankrupt the whole operation, and they don’t have enough confidence,” Chris Gadomski, the lead nuclear analyst at the consultancy BloombergNEF, told me.
The workforce that constructed the two AP1000s at Vogtle, he said, are now out building data centers. Unlike the Chinese, whose state-owned nuclear companies reverse engineered the AP1000 and made it relatively cheap to build by constructing as many as half a dozen at a time at one location, “we don’t have the wherewithal or sites in this country to build six reactors at once,” Gadomski said. “You’re lucky to build two at one site in this country.”
So fusion and next-generation fission remain years away. Current-generation SMRs come with big questions. And the leading large-scale design, the AP1000, is proving a hard sell to utilities. That leaves two options: Restarting decommissioned plants and uprating current reactors. The Energy Department has pumped billions in loans into projects to restart at least three permanently closed reactors: Holtec’s Palisades plant in Michigan, NextEra’s Duane Arnold facility in Iowa, and Constellation’s Crane Clean Energy Center, née Three Mile Island, in Pennsylvania. The consensus among industry experts is that those are the only three that remain intact enough to start back up; every other shuttered plant is at too advanced a stage of demolition.
That leaves uprates.
There are limits to how much power can be drawn from existing plants, said Jeff Jenkins, the founder and managing partner of Bernhard Capital Partners, an investment firm whose portfolio includes Allied Power, a contractor that has worked with Constellation on past uprates. “There’s still a few gigawatts out there,” he said. “And a gigawatt is a lot.”
But ultimately, the U.S. nuclear buildout needs options.
“It’s very much a hedge,” Gadomski said. “They’re spreading their bets. That’s a strength of Google’s strategy. They’re willing to place bets on advanced reactors, fusion, and still try to double down on the capacity of existing plants.”
On methane rules, British wind, and the Israeli electricity market
Current conditions: Singapore’s air is the worst in the world as wildfire smoke from Indonesia chokes the city state and neighboring Malaysia • Following a summer-like heat wave, temperatures in the American West are set to drop by as much as 50 degrees Fahrenheit as a cold snap moves in • In the Gulf of Mexico, Tropical Storm Isaias officially strengthened into the first Atlantic hurricane of the season this morning.
With its offshore oil fields booming in Guyana and its opportunities opening in Venezuela, Exxon Mobil is eyeing the next location for the Americas’ oil and gas: Trinidad and Tobago. In an interview with the Financial Times this week, the company’s exploration chief said the island nation’s existing oil and gas industry could expand to tap the same basin east of Venezuela that has transformed Guyana from one of the hemisphere’s poorest nations to one of its richest in terms of per capita gross domestic product. “A lot of people ask, ‘well, where’s the next Guyana?’” John Ardill, Exxon Mobil’s vice-president and head of global exploration, told the newspaper. “In Trinidad, we moved in as a play extension to Guyana.” The agreement between Exxon Mobil and the Trinidadian government took “about half as long as it usually takes on a good day,” delivering a pact in “record time.”
America’s oil majors are also looking outside the hemisphere. As you may recall from August, I told you that Exxon Mobil was also considering a big investment in Africa, with Mozambique drawing particular attention. Brazil’s state-owned Petrobras, meanwhile, is expanding its own grasp on the Americas’ oil boom. On Wednesday, Upstream reported, the company bid $590 million for control of an ultra-deepwater concession.
The European Union is pausing implementation of its new rules requiring oil and gas exporters to more scrupulously track data on methane emissions. The U.S., on the other hand, is planning a straight-up rollback. At an oil industry conference in Santa Fe on Wednesday, Environmental Protection Agency Administrator Lee Zeldin teased out plans to gut core parts of the methane regulations finalized in 2024. “This proposal takes on many of the problems American producers and operators have raised with us,” Zeldin said, according to Argus Media. “That includes the burden on marginal wells and oil and gas operators in general, the super emitter program, associated gas and control device requirements.”
Record wind power generation may have slashed how much natural gas Britain needed to burn last month for electricity, but it “wasn’t enough to shield the country from surging prices triggered by the war in Iran,” Bloomberg reported. Wind turbines pumped out 6.6 terawatt-hours of electricity in September, a record for the month and 4% more than a year earlier. As a result, gas-fired generation plunged to its lowest level on record for that month. But day-ahead power rates still doubled from a year earlier.
The world’s capacity of floating offshore wind, the subset of the sector that could vastly expand the areas of shoreline dotted with turbines, has reached 382 megawatts, a 38% surge over the past 12 months, according to a Renewables Now writeup of the latest report from the trade group RenewableUK. Meanwhile, Poland has now constructed all 76 of the standard turbines built into the seabed of the Baltic Sea for its first offshore wind farm. One-third of the turbines are now generating power, according to offshoreWIND.biz.
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South Korea plans to speed up its shift away from fossil fuels with a new goal of 100 gigawatts of low-carbon energy additions by 2030 and roughly $747 billion in government-led investment over the next decade. The plan, part of the Korean Green Transformation program, “seeks to make Korea one of the world’s top three green manufacturing powers by developing industries such as hydrogen-reduction steelmaking, next-generation solar cells, and all-solid-state batteries,” according to The Korea Times, an English-language daily. New nuclear reactors are also part of the strategy.
The move comes as Seoul advances construction of as many as eight nuclear reactors in the U.S., including six of America’s Westinghouse AP1000 and two of its own APR1400s, as I told you last week.
The utility megamerger of the century so far is “not in the best interest of Virginians.” That’s the judgment the state’s lieutenant governor, Ghazala Hasmi, rendered this week following a five-city public listening tour. The statement came ahead of the State Corporation Commission’s first local hearing on the deal, and marks what Utility Dive called “the most formal expression of opposition from Virginia’s executive branch so far.” Governor Abigail Spanberger, a fellow Democrat, has not yet taken a definitive position on the merger.
But the deal follows some clear market logic. Among the benefits: It would create, as my colleague Matthew Zeitlin wrote in May, “a storage juggernaut.”

Israel’s booming tech sector and soaring stock market are just two ways its economy has dramatically changed from the socialism that defined the early decades after the country’s founding in 1948. Now that shift also includes the electricity market. Since market reforms allowed private actors into the grid at the start of last year, more than 2 million citizens, representing more than 500,244 private and business customers, have switched from the Israel Electric Corporation to private providers, according to The Jerusalem Post. Ratepayers buying electricity from private suppliers enjoy discounted rates ranging from 7% to 20%, “thanks to the lower generation costs in the private market.” Another 23,286 households and businesses submitted requests to switch suppliers just last month. OPC Energy, an independent power provider based in Tel Aviv, raised $200 million in bond issuances in August.