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Counties that veered from Obama in 2008 to Trump in 2016 are more likely to oppose renewables development.

In Texas, the Oak Run Solar Project would have been a slam dunk.
Developers would install 800 megawatts of solar panels — enough to power 800,000 homes — across nine square miles of unused land. It would devote some of its acreage to new farming practices that incorporate solar panels. And it would sell its electricity cheaply — and profitably — because it was near the state capital and because it could take advantage of a pre-existing onsite connection to the regional power grid.
But Oak Run wasn’t proposed in Texas. It was proposed in Ohio, and that means it has faced enormous opposition. Ohio has some of the country’s strictest restrictions on solar development, and 10 counties have blocked solar development outright.
Although Madison County, where Oak Run was proposed, is not one of them, the blowback to the project cost a local Republican county commissioner his job. Oak Run was eventually approved by the state’s power siting board earlier this year, but its opponents are now appealing that decision in the state’s Supreme Court.
Madison County, Ohio, also illustrates the political transformation that has revolutionized the upper Midwest. The predominantly rural county near the state’s capital, Columbus, has favored Republicans since the 1960s. But in recent decades it has swung hard to the right. In 2008, Barack Obama won nearly 40% of the county’s vote. Eight years later, Hillary Clinton picked up just 27%.
These two facts may seem like they have little to do with each other. But they point to one of the biggest trends in clean energy development across the country: The counties that voted for Barack Obama in 2008 and then Donald Trump in 2016 are some of the worst places in the country to permit and build renewable projects.
The size of a county’s swing from 2008 to 2016 is one of the biggest predictors of whether a proposed wind or solar project will be contested or blocked, according to a new Heatmap Pro analysis of more than 8,500 projects and local policies around the country.
The magnitude of that swing is by far the most important political variable to emerge from Heatmap Pro’s analysis of more than 60 risk factors influencing community support or opposition to renewable projects. It is more strongly associated with a given project’s success than whether a county votes for Democratic or Republican candidates overall.
The only variables that are more closely correlated than the 2008-to-2016 swing are fundamental measures of a region’s population or local economy, such as its median income, racial demographics, or dominant industries. Towns and regions that heavily depend on farming, for instance, have become particularly reluctant to accept new solar projects in recent years.
Heatmap Pro’s analysis focused not only on whether a county’s residents support wind or solar projects in theory, but also on whether renewable projects proposed in the area are canceled, contested, or exposed to political turbulence. It surveyed more than 7,000 wind and solar projects proposed and built across the United States since the 1990s.
Many of the counties with the largest Obama-to-Trump swings have passed proposals meant to limit renewable development. Vermillion County in Indiana — where more than a quarter of voters swung from Obama to Trump — has an extensive set of restrictions on new solar projects. Solar projects in Elk County, Pennsylvania, which saw a similar swing, have also turned out against solar projects using up “prime farmland.”
There are a few reasons why the Obama-to-Trump swing might be associated with more opposition to renewables.
In 2008, solar and wind were still frontier technologies and were not price-competitive with fossil fuels. Although vaguely associated with Democrats, politicians on both sides of the aisles championed wind and solar so as to wean the country off foreign oil.
But in the following decade, the U.S. increased its solar capacity by roughly 100-fold, while it has more than doubled its installed wind capacity.. Today, solar and wind energy are major features of the electricity system, and many Republicans have openly embraced fossil fuels and cast doubt on the value of cleaner alternatives.
To be sure, the Obama-to-Trump swing was influenced by other social and economic factors, as well as a state’s specific political environment. Leah Stokes, a UC Santa Barbara political scientist who has studied the growing local opposition to wind farms, told me that the correlation with Obama-Trump voters may originate from Trump’s dominance of the upper Midwest in 2016. Because a small group of anti-renewable advocates can change an entire region’s policies, that could lead to more opposition to renewables in one part of the country or another.
“Is there a person, or a network of people, who are going place by place pushing these anti-solar and wind local laws? That would lead to a geographic concentration,” she said.
Even within individual counties, the electorate wasn’t the same in 2016 as it was in 2008. Throughout the 2010s, tens of millions of Americans moved around the country, with the largest net change moving from the Northeast to the South. Cities became younger on average, while rural areas and suburbs became older.
Even within counties, a different set of voters showed up to the polls in each election. One reason why the 2012 election might not be correlated with opposition to renewables is that many voters who voted for Obama in 2008 skipped the next cycle. Those same voters — many of whom were white and working class — showed back up in 2016 and backed Trump.
What is driving the opposition to renewables? Perhaps a county’s swing against renewable energy is happening precisely because voters there are persuadable. From 2008 to 2016, many voters in these counties changed their minds about which candidate or political party to support. As they shifted their stance to the right, they also adopted more seemingly Republican views about wind and solar development. Donald Trump has distinguished himself by his embrace of fossil fuels and climate change skepticism — perhaps as voters come to support him, they also adopt his positions.
What’s interesting, however, is that deep red counties that have not seen a political shift — places that backed, say, McCain and Romney by roughly the same margin as they backed Trump in 2016 — continue to build wind and solar at a good clip. Texas, for instance, is the No. 1 state for renewable deployment. A county’s partisanship, in other words, is not as good a predictor of its opposition to renewables as its swinginess.
Edgar Virguez, an energy systems engineer at the Carnegie Institution for Science at Stanford University, has studied what drives opposition to renewables in North Carolina. He told me that some of the same factors that predict a county’s Trump support — such as its population density and education level — also predict whether that county has enacted a local restriction on renewable energy.
When he and his colleagues studied local policies in North Carolina, they found that lower density and less educated counties “had significantly higher reductions in the land available for solar development” when compared with denser or more educated counties, he said. Once a county has fewer than 35 people per square mile, or when less than 20% of the population has a bachelor’s degree, the number of restrictions on local land use shot up. That’s a problem for decarbonization, he added, because less dense counties also usually have the best and most affordable land available for solar development.
That finding may not hold true in other states. Heatmap, for instance, has found that whiter and more educated counties are more likely to oppose renewables. And to some degree, less dense counties are exactly where you’d expect to see more solar and wind projects get built — and thus more local policies restricting them pop up. But it is nonetheless not great news for advocates, given that a couple of America’s political institutions — namely, the Senate and the Electoral College — favor rural voters or Midwestern states. If the trend takes root, then it could eventually curtail renewable development across the country. That question — and many others — will partly be decided in this week’s presidential election.
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Pennsylvania Governor Josh Shapiro and Berkshire Hathaway CEO Greg Abel agree: The “regulatory compact” is breaking down.
What are utilities anyway? And what are they supposed to do? Elected officials, regulators, utility executives, and scholars are asking fundamental questions about the so-called “regulatory compact” that has governed electric utilities for — depending on who you ask — decades or a century.
Two events in the past week crystallized the moment of transition electric utilities find themselves in.
In Pennsylvania, Governor Josh Shapiro, wrote a letter to the state’s utilities (including water and gas), telling them that “the 20th century utility model is broken,” citing “markedly higher utility costs” and “rising utility bills” which he claimed were in part the “result from your policy and fiscal decisions, including the excessive rate requests several utilities have sought in recent years.”
And over the weekend at the Berkshire Hathaway annual meeting, its new chief executive Greg Abel, who came up in the conglomerate through its energy division, was also speculating that utilities may be at a precipice. “What’s the challenge? It’s the regulatory compact,” Abel said at the company’s annual meeting.
The way he explained the utility business, “We leave your capital, our owner's capital, Berkshire’s capital, in these businesses, and often a portion of the earnings that they generate, we may reinvest back into those businesses. And for that, we get a very specific set of returns. And, over the long run, it’s been a very balanced and fair return,” Abel said, referring to the setup where utilities make investments approved by state regulators for which they receive a regulated return on their capital. “That model has worked very good for a number of years,” Abel said.
But, he cautioned, that model is becoming “more stressed.”
The dilemma, Abel said, was that utilities’ have high investment needs, including from replacing existing assets, while state regulators and governors want to keep rates as low as possible. “If we don’t see that balance, we don’t deploy our capital back into those businesses or into those utilities.”
The Berkshire Hathaway-owned utility PacifiCorp, which operates in the Western United States, has been challenged by high legal claims stemming from wildfires, especially in Oregon, and has been seeking to get legislation passed in a number of states to limit wildfire liability.
Earlier this year, it agreed to sell almost $2 billion worth of assets in Washington state, citing “diverging policies among the six states PacifiCorp serves [that] have created extraordinary pressure, affecting the company’s ability to meet demand reliably and at the lowest cost to customers.”
The utility was threatened with credit downgrades following large jury awards stemming from wildfire claims in Oregon. Washington is also a state with an aggressive decarbonization timeline and mechanisms that PacifiCorp has chafed against, claiming they would raise costs for its customers in other states.
Americans everywhere are angry about electricity costs but utilities think too much is being demanded of them to profitably run their businesses.
In the West, those high costs stem from wildfire-related damages that existentially threaten utilities. (PG&E in California even went bankrupt over wildfire liability.)
On the East Coast, electricity costs are rising in part due to data center construction and the structure of PJM, the 13-state electricity market that runs from Washington, D.C., to Chicago. Here, elected officials are angry at utilities for skyrocketing costs while those who manage the electricity market say that the real issue is regulatory barriers to bringing on the new generation they think they need (i.e. gas).
In both cases, the “regulatory compact” — utility investment in exchange for regulated rates that allow future investment — is seen as under threat.
Where Greg Abel sees the model endangered by uncapped liability and decarbonization mandates, Shapiro sees the threat in higher costs to consumers. Over the past five years, electricity prices in Pennsylvania have risen 47% while average bills have grown 49%, from $116 per month to $169, according to the Heatmap-MIT Electricity Price Hub.
“We can no longer simply prioritize corporate profitability to drive infrastructure development,” Shapiro wrote in his letter.
The commonwealth’s government has been doing more than just writing letters. The utility PECO Energy, a subsidiary of Exelon that serves the Philadelphia area, withdrew a recent rate case in April asking for over $500 million worth of electricity and gas rate hikes. The Governor’s office didn’t just claim credit for the pulled rate case, it announced it, with Shapiro saying in a statement, “PECO’s proposed rate case would have increased Pennsylvanians’ utility bills, but I demanded that their CEO put customers first and withdraw their rate hike request.”
Now Shapiro wants more fundamental reforms to how utilities operate in the state, including asking the utilities to fund themselves more by borrowing money, including from the federal government through Department of Energy programs.
“Consumers should not be expected to bolster corporate profits through over reliance on costly equity,” Shapiro said in his letter, and asked that utilities fund themselves with a “clear majority” of borrowed money.
Utilities have high investment needs. They finance these with a mix of debt (borrowed money) and equity (shares it sells to investors). They then gets a regulated return on the equity portion of its total approved capital investments, known as its “rate base.” That return on equity is recovered through ratepayers’ bills.
Berkshire Hathaway’s Abel argues that if the utility business becomes less appealing to investors, there will be less investment. But Shapiro thinks that there’s a lower cost way to finance utility investment, money borrowed from investors, i.e. debt. His approach rhymes with other utility reformer ideas around lowering the return on equity that utilities ask for in their rate cases, often around 10%.
“The average Pennsylvania utility requested a return on equity a staggering 682 basis points above the 10-year U.S. Treasury yield last year. Before raising such expensive equity, you should take advantage of more affordable sources of capital,” Shapiro wrote.
For the equity utilities do fund themselves with, Shapiro writes, those returns must be “transparent” and “justifiable,” and no longer be based on “educated guesses.” He instead proposed a market process to determine a fair return based on “competitive bidding by multiple participants to establish a fair market cost of that equity” or setting one by a combination of returns on government debt and a measure of the returns stocks get over debt on average.
Shapiro’s proposal could take down Pennsylvania utilities’ return on equity down to the “high 8%s” according to Jefferies analyst Julien Dumoulin-Smith. In the now-withdrawn PECO rate case, the requested ROE was almost 11%. (Other utility reform advocates have called for pulling ROEs down to around 6%.)
As a result, Dumoulin-Smith argues, Pennsylvania utilities “could see authorized ROE trends well below peers in prospective rate cases,” which will mean “gradual capital expenditure reductions to align with the new reality,” i.e. less investments by utilities in new transmission and distribution lines, substations, and other grid infrastructure even as demand increases.
This gets to the crux of utility regulation at a time of public anger at ballooning prices: how will utilities be able to revamp an aging grid, prepare for electrification of home heating and transportation, build news transmission for new renewable resources, and build out the grid infrastructure necessary for the data center boom? And what about that wildfire liability? All while making a fair return for investors that passes musters with regulators, elected officials, and voters?
The answer many have come up with is to transform the “regulatory compact.” This can mean, as some scholars have proposed, not offering firm service to all new customers. It can mean getting data center developers and their customers to specifically pay for grid upgrades.
In the case of wildfire liability, the California Public Utility Commission has declared that the set-up of the modern regulatory compact in the Golden State, with utilities required to serve all customers in the state (including in severe fire hazard areas) and then be liable for damages that get passed on to ratepayers, is “unsustainable.”
“Our existing system places outsized and unsustainable burdens on utilities and utility ratepayers to mitigate the risks of wildfires and pay for wildfire damages,” the CPUC wrote in a report mandated by a recent wildfire bill. This translates to higher borrowing and cost of equity for utilities, as well as higher rates.
The CPUC recommended a version of opening up the compact, arguing that the state “should consider funding a portion of utility wildfire mitigation from non-ratepayer sources,” including the state’s general fund (i.e. taxpayers). This echoes Shapiro’s proposal to have the state fund itself with cheaper public equity.
“Public debt is typically cheaper than private credit,” Josh Macey, a professor at Yale Law School, told me.
Another approach is to limit what utilities owe, thus ensuring that they can maintain reasonable returns and stay in business in the states they operate in.
In Utah, Berkshire Hathaway was able to win liability limitations for wildfires, including time limits on claims, the ability to use ratepayer dollars for wildfire mitigation plans, and limiting utility liability from wildfire claims if they comply with wildfire mitigation plans, a model it has tried to export to other states PacifiCorp operates in.
But do all these challenges to utilities represent the end of the “regulatory compact,” as Abel might put it?
For Abel, he claims that changes (or lack thereof) in state law have led to Berkshire’s exiting Washington and potentially other states. In Pennsylvania, analysts claim that changes to the debt-equity mix could mean fewer capital investments. In California, state regulators think utilities are being asked to do too much.
But will these utility reforms mean the death of the utility model itself? Maybe not — after all, PacifiCorp was able to sell its Washington assets to another utility.
The compact is “a kind of political intuition that if we’re asking them to provide low cost, consistent service, we have to give them a real right to kind of recover the costs and earn a steady profit,” Macey said. “It’s hard for me to imagine how that could break down, because if you really see a state not allow a utility to have some chance of doing good business in the state, the utility will not be able to attract capital, and as a political matter, the state will not be able follow through with that.”
Where the company is trying to restart its electric car program from scratch
Two thousand miles from Detroit, just across the road from the runways of Long Beach Airport, the future of Ford is taking shape. What that shape is, however, the company isn’t quite ready to share yet.
Last week, the automaker invited some members of the car press inside the secret compound where Ford is developing its next battery-powered vehicle, an affordable midsize pickup truck due out next year. Although the actual appearance of that truck is a closely guarded secret, as is just about everything else about it, Ford wanted to show off its launchpad, the Electric Vehicle Development Center. The research and development campus, with its two white warehouses glimmering in the Southern California sun, is about more than one car. Inside, teams of engineers, coders, and designers are trying to reinvent how Ford makes vehicles in the hopes of turning around its fortunes in the electric era. As the company at large has canceled EV models and infrastructure and taken on billions of dollars in losses to transition some of its EV assets back to combustion, EVDC represents its one big chance to find a way forward in electric cars.
Ford knows it’s at an inflection point. The company’s first forays into making mainstream electric cars, such as the Mustang Mach-E and Ford F-150 Lightning, were quality vehicles that beat many established automotive rivals into the space. But Ford struggled to keep costs down and wound up losing billions as it tried to scale up an electric car business.
Something had to change. Last year, CEO Jim Farley said Ford would restart its electrification efforts through a skunkworks team, a small unit that would rethink how it builds EVs. “They're from all over the place,” Alan Clarke, the executive director of advanced EV development, said of the skunkworkers during our visit last week. “Some of them are from startup EV, some of them are from established EV. Many come from consumer electronics, startup aerospace companies, and you'll meet many of them today, but there's also many that have come from Ford. Many of them have waited decades for a moonshot like this.”
The group studied EV brands like Tesla and Rivian that simplified their electrical and computing architectures to strip miles of expensive wiring from their vehicles. They worked fast and leaned in a way meant to echo Silicon Valley more than Motor City. The result is the Universal EV platform that will underlie not only next year’s new truck, promised to start in the $30,000s, but also a variety of vehicles to come, creating manufacturing savings that will hopefully allow Ford to sell more affordable electric cars.
Even the California locale is no accident. It’s meant to call back to a time when the brand was the innovator, not the establishment , with the hope that the secret sauce of the past can propel Ford back into a race dominated by startups – and now by rivals like GM and Hyundai that beat Ford to the punch with better EV platforms. The facility itself is already 100 years old, built to expand production of the Ford Model A in the 1920s and 30s.
Inside, EVDC represents a full embrace of the frictionless workplace: no corner offices, just open rows of computers amid a makeshift garage brimming with 3D printers, spools of wiring, and racks of gear. Coders are a short stroll from the visual designers tinkering with clay models. Electrical engineers are around the corner from the “lab car,” a rectangular steel frame meant to suggest the general shape of a vehicle, with a complete mockup of the future car’s electrical system strung along the skeleton so that workers can test any part of it. This is about process; the closest thing to the shape of a car is a wooden one with test car seats inside, set up in the fabrication shop. The shepherds of our tour met any question about the specifics of the forthcoming truck with a quick you’ll find out next year, though a prototype dressed up in that zebra camouflage just happened to sneak by as we moved between building.
The point of all this is to innovate at speed, without the barriers inherent in the old-fashioned hierarchical struggle that governs an established business. Any idea that can make a car a little bit better, or cheaper, is welcome. It can come from something as simple as fabric on the seats. In the seating lab, Scott Anderson is using new algorithms to lay out the necessary shapes to be cut from a sheet of fabric with the least possible waste.
The more pressing concerns for an electric car lie in the battery, though, since that unit still makes up about 40% of the cost of an EV. On Ford’s campus, a chamber is coming together that will test cells under just about any climatic conditions, from about -40 degrees Fahrenheit to 150 degrees. Inside a thermal lab dedicated to battery development, engineers can build and test battery cells in the same location. As with every department at EVDC, the point is to be able to prototype, test, and move on to the next iteration within a couple of weeks rather than the months it might have taken before.
The lessons that emerge from Long Beach are meant to spread throughout the Ford ecosystem. For example, EVDC researchers are working on ways to build EVs from three modules that can be assembled separately and come together toward the end of the process. It’s a plan that’s meant to double as a life improvement for workers at the plant in Louisville, Kentucky, that will build Ford’s EV pickup truck — they can, for example, work on brake pedals while standing up rather than sitting awkwardly in the driver’s seat and reaching down to the footwell.
That is the eternal skunkworks challenge. It’s not enough to establish a small team charged to move fast and break things without the suits there to say no. Their innovations must really take root. Ford, at least, seems to understand the urgency at the very top. Farley, the CEO, has been especially vocal among industry bigwigs about the existential threat of cheap Chinese EVs, which lots of American drivers would buy if they could. EVDC will not magically allow Ford to compete at Chinese’s pricing level. But by restarting its EV program from scratch, Ford’s version of the Apollo program, it could follow a manufacturing path that’s competitive with the likes of Tesla and with the electric offerings of its longtime rivals. Compared to the status quo of losing billions every year on electrification, that would indeed be a giant leap.
Current conditions: Severe thunderstorms are drenching the American South from New Orleans to Virginia Beach • Mount Mayon has forced thousands to evacuate within the Philippines’ Bicol peninsula • Temperatures in Denver are poised to plunge from about 75 degrees Fahrenheit yesterday to 39 degrees today with a chance of snow.

The North American Electric Reliability Corporation, the quasi-governmental watchdog that monitors the health of the power grids that span the United States and Canada, has issued a rare Level 3 warning. The alert, announced Monday, marks only the third time NERC has put out a notice with that degree of severity in its 58-year history. The warning comes on the heels of reports that data centers abruptly went offline in Virginia and Texas, prompting concerns of potential blackouts. “Computational loads, such as data centers, could increase exponentially in the next four years,” NERC said in a draft of the alert, adding that “significant risks” to the power network “need to be addressed through immediate industry action.” Lee Shaver, a senior energy analyst at the Union of Concerned Scientists, told E&E News that NERC’s action was a “big deal.”
The California Energy Commission has issued an administrative investigative subpoena to Golden State Wind seeking documents and information related to the company’s recent deal with the U.S. Department of the Interior to take a payout in exchange for abandoning its offshore wind lease. Last week, the developer announced a deal to scrap its lease in the Morro Bay Wind Energy off the central California coast for $120 million as part of the Trump administration’s efforts to kill off an industry he failed to destroy through regulatory fiat alone. The facility was supposed to be California’s first offshore wind farm, and planned to use floating turbines to account for the steep continental shelf dropoff on the nation’s Pacific Coast. Now the administration’s latest “shady deal” is drawing scrutiny from state regulators. “The Trump Administration is recklessly spending billions of taxpayer dollars on backroom deals that would turn back the clock on innovation,” David Hochschild, the chairman of the California Energy Commission, said in a statement. “Californians deserve immediate answers about the nature of this payout. Taxpayer dollars should be used to build a sustainable energy future, not to pay to make projects disappear.”
Meanwhile, California’s grid operator has switched on a new regional electricity market as part of what E&E News called “a major milestone in the yearslong push to expand energy trading” across the American West. The California Independent System Operator launched its new Extended Day-Ahead Market early Friday morning, allowing California’s investor-owned utilities and the Northwestern giant PacifiCorp, whose coverage area spans two million customers across six states, to trade electricity on the regional market for the first time. “The West is rich with a diverse mix of renewable resources, and this market will capture their potential,” Michael Colvin, director of the California energy program at the Environmental Defense Fund, said in a statement. “Through better sharing of cheap, clean energy beyond state borders, the market will cut household bills, reduce reliance on expensive, polluting fossil plants and build a grid that's bigger than any single extreme weather event.”
For nearly as long as there have been nuclear power plants, there have been thorium bulls insisting the metal is a better fuel than uranium. In most places, the thorium dream faded long ago as ample new sources of uranium were discovered. But China revived the thorium race in 2023, when its experimental molten salt reactor powered by the metal split atoms for the first time. Now the only serious contender in the entire West looking to commercialize thorium is a Chicago-based company taking an unusual approach. Rather than creating a whole new kind of reactor to run on thorium, Clean Core Thorium Energy has designed fuel assemblies that blend thorium with a special kind of uranium fuel and work in existing reactors without any modifications. Clean Core’s technology only works, at least for now, in pressurized heavy water reactors, which make up the bulk of the fleets in Canada and India, though the U.S. has none in operation. But the key verb there is that: It works. On Tuesday, I can exclusively report for this newsletter, Clean Core plans to announce that its patented fuel completed a high burnup irradiation test at Idaho National Laboratory’s Advanced Test Reactor. The fuel burnup represented “more than eight times the typical” output from the traditional uranium fuel used in pressurized heavy water reactors. The latest test “provides meaningful performance data” and demonstrates that Clean Core’s fuel “achieve burnup levels comparable to those seen in PWR fuels while offering improved fuel utilization, enhanced safety characteristics, inherent proliferation resistance, and meaningful reductions in long-lived nuclear spent fuel radioisotopes,” Mehul Shah, Clean Core’s chief executive, told me in a statement. “Our objective has been to introduce thorium into the nuclear fuel cycle in a practical way using existing reactors, and this milestone represents a significant step toward that goal.”
It’s the latest good news for Clean Core. Last month, as I reported for Heatmap, the company inked a deal with the Canadian National Laboratories to manufacture its first commercial fuel assemblies.
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In July 2017, South Carolina abandoned its $9 billion expansion of the V.C. Summer Nuclear Station, leaving ratepayers holding the bag and utility executives facing prison time for lying about the project’s viability. Now the pair of Westinghouse AP1000s planned at the site are making a comeback. On Monday, Westinghouse-owner Brookfield Asset Management formed a new joint venture with The Nuclear Company, a reactor construction manager, to work together on building more Westinghouse reactors such as the AP1000 or the smaller version, the AP300. V.C. Summer is the likely first project. “Our team was built on the field of Vogtle and on some of the most complex energy projects in the world,” Joe Klecha, The Nuclear Company’s chief nuclear officer, said in a statement. “We know what it takes to deliver nuclear. What’s been missing is a model that brings together the people, the capabilities, and the capital to do it at speed and scale. That’s what this partnership creates.” The announcement comes as the Trump administration meets with utility executives to discuss funding deals to build the 10 new large-scale reactors President Donald Trump ordered the Department of Energy to facilitate construction on by 2029, as Heatmap’s Robinson Meyer reported. Completing 10 AP1000s would give the U.S. economy a trillion-dollar boost, per a PricewaterhouseCoopers report Westinghouse released in March.
That’s not the only nuclear developer making deals. On Tuesday morning, Blue Energy, another startup focused on serving as a project developer for existing reactor designs, announced a partnership with GE Vernova to work on building the world’s first gas-plus-nuclear plant in Texas. The 2.5-gigawatt project would include GE Vernova’s gas turbines and its BWRX-300 small modular reactors through its joint venture with Hitachi. “Innovative projects like this one will help advance the future of nuclear power and meet the surging demand for electricity,” Scott Strazik, GE Vernova’s chief executive, said in a statement.
Steel, if you’re unfamiliar, is made in two big steps. Traditionally, iron ore is melted down in a coal-fired blast furnace, then forged into steel in a basic oxygen furnace. New plants typically run on something called direct reduced iron, which uses natural gas to turn the ore into iron, then made into steel in an electric arc furnace. The latter process is far cleaner. It can even be green, if the natural gas is swapped for green hydrogen and the electric arc furnace is powered by renewables or nuclear reactors. Nearly 40% of all global clean steel investments to date are hydrogen-powered DRI facilities. That’s according to new data from the Rhodium Group, which released its latest estimates Tuesday. Another 57% of investments are gas-powered DRI plants. While Europe has so far dominated investment into hydrogen DRI, “the region will likely see relatively little demand growth for iron over the coming decades,” the report found. In the fastest growing regions, such as India, Africa, and South America, “most new demand is being met with traditional, fossil-based ironmaking technologies, which risks locking in emissions for decades.” The consultancy’s modeling shows that clean steel supply capacity is on track to exceed demand by between 1.8 and 4.3 times by 2030, “risking a collapse of the nascent industry, where existing projects cannot find buyers and scale production to drive down costs.”
It may be time for a new New Orleans. The city has reached a “point of no return” that will see it surrounded by ocean within decades as climate change worsens. That’s the conclusion of a new paper in the journal Nature Sustainability. “In paleo-climate terms, New Orleans is gone; the question is how long it has,” Jesse Keenan, an expert in climate adaptation at Tulane University and one of the paper’s five co-authors, told The Guardian.