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If the “nuclear renaissance” is here, it’s happening only in certain kinds of places. California and New York aren’t getting new reactors capable of generating massive amounts of always-on, carbon-free power — instead projects are being completed and planned in Tennessee, Georgia, and Idaho. It’s not all red state friendliness to new development and blue state fears of nuclear waste either. It’s really about how electricity markets are organized across the United States.
There’s simply little new nuclear activity in the vast swaths of the country, like much of the Northeast and Midwest, Texas, and California, where electricity markets have been partially or completely “deregulated,” meaning that utilities largely buy electricity from generators and distribute it to consumers in something like a free market. Instead, nuclear projects are popping up in markets, like those in the South and Mountain West, where utilities still control both electricity generation (think power plants) and the distribution of that electricity to customers and where public power companies can still predominate in the market. In these areas, energy companies have the scale, authority, access to investment, and captive customer base necessary to embark on capital intensive projects like nuclear generators.
This is of note because the Department of Energy estimates that in order to decarbonize the power system, some 550 to 770 gigawatts of new clean firm capacity, meaning generators that can be turned on 24/7, will be necessary. While this could include geothermal, solar or wind paired with batteries, or pumped hydro, there’s already some 94 gigawatts of existing nuclear capacity that the Energy Department anticipates could scale to around 300 gigawatts by 2050.
Where that’s been expanded recently is not necessarily the parts of the country that have an aggressive mandate to decarbonize.
Consider Georgia’s Vogtle-3 reactor, the United States’ first new nuclear reactor in years. The end result is a staggering amount of non-carbon-emitting power, but delivered at an eye-wateringly high cost (some $16 billion overbudget) in a market set-up where an investor-owned, vertically integrated utility — Georgia Power, a subsidiary of Southern Company — is able to charge ratepayers for high construction costs. Or Watts Bar Unit 2, a new reactor built by the Tennessee Valley Authority, a government power company with a monopoly on electricity in Tennessee and bordering states (it had its own set of delays — for decades — and cost overruns).
A similar dynamic is at work when it comes to the next generation of nuclear technology. The Carbon Free Power Project is a planned set of small modular reactors at the Idaho National Laboratory that a coalition of Mountain West public utilities have been working on and hope to make operational by the end of the decade.
The dream of small modular reactors is that, by standardizing construction processes and parts and also by literally making the projects smaller, construction costs for nuclear power can be brought down as more projects get completed. That being said, the Carbon Free Power Project has still reported large cost escalations. And it’s doing so with funding from the Department of Energy that could amount to around $1.3 billion of the over $9 billion it’s expected to cost if the project actually starts generating power as scheduled in 2029. Some members of the coalition have already dropped out and the projected price of power generated by the reactors has increased.
That’s not a huge surprise. Cost is really what’s holding back nuclear power.
The great scaling of renewable power across the country has been, its advocates always like to say, a triumph of the market. Wind and solar projects, while expensive to set up, are cheap to operate over time, in part because they have no fuel costs, compared to thermal plants which must acquire and combust coal, oil, or natural gas. In fact, around two thirds of the price of natural gas-generated power comes from the fuel itself, which actually hasn’t been a huge problem for natural gas over the past 15 years since it’s been so cheap.
On the other hand, the vast majority of the costs of nuclear power come from the expense of building its generators, according to an analysis by Brian Potter, a fellow at the Institute for Progress and a contributor to Heatmap. With gargantuan capital requirements and long construction timelines, interest payments on financing can end up doubling the total costs of nuclear plants. When those costs get reflected in the price of nuclear energy on so-called deregulated electricity markets, it becomes uncompetitive.
Regulated markets are a different story, however. Utilities that own power plants have massive cash flows and legally mandated profits that let them borrow huge amounts of money at the lower costs necessary to finance large, capital-intensive construction projects like nuclear plants — and then put the costs directly into ratepayers' bills.
“These larger utilities have a larger balance sheet, they can carry a larger project on their books without it being a huge percentage of their net debt at any point in time,” Adam Stein, the director of the Nuclear Energy Innovation program at the Breakthrough Institute, told me. The Tennessee Valley Authority also has a large capacity to carry debt, while public power companies “have experience and expertise internally in how to engage in the DOE grant process,” Stein said.
Critics of deregulation and advocates for nuclear power argue that the way those markets work does not properly value power that is not variable, like wind and solar, and can keep their fuel stored on site, unlike gas, which relies on pipelines. Despite the unique role it can play on the grid, nuclear power still has to compete on the same playing field as other assets which are intermittent or rely on getting fuel, Stein explained.
But utilities that control both generation and distribution aren’t immune from market forces, even if they can withstand them better. One reason why deregulation took hold in much of the county is precisely because there was so much backlash to utilities’ nuclear power plant projects that were more expensive than projected and assumed more electricity demand than there actually was.
“The ratepayers were paying a lot for the nuclear plants, and they were unhappy with it,” Meredith Angwin, an energy analyst and critic of deregulation, told me. “Cost per megawatt of nuclear plants, it’s just rising. There’s a learning curve that makes things less expensive — with nuclear it goes the other way.” Figuring out exactly why this happened — and how to reverse it — has been the great challenge of the nuclear industry and energy policy experts.
Many advocates for increased use of nuclear power see new construction techniques, plant designs, and more well-tailored regulation as the answer to these rising costs.
And while there have been large declines in the cost of renewables over the past decade, wind and solar projects have run into cost issues recently thanks to economy-wide inflation and specific issues with supply chains.
Offshore wind in the United States, which currently has a few dozen megawatts of capacity that the Biden administration wants to scale up to 30 gigawatts, is facing a crisis of high costs, with wind developers demanding more money to complete projects and even threatening to cancel them altogether, lest they get access to more subsidies. It’s a story we’ve heard before.
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The Loan Programs Office is good for more than just nuclear funding.
That China has a whip hand over the rare earths mining and refining industry is one of the few things Washington can agree on.
That’s why Alex Jacquez, who worked on industrial policy for Joe Biden’s National Economic Council, found it “astounding”when he read in the Washington Post this week that the White House was trying to figure out on the fly what to do about China restricting exports of rare earth metals in response to President Trump’s massive tariffs on the country’s imports.
Rare earth metals have a wide variety of applications, including for magnets in medical technology, defense, and energy productssuch as wind turbines and electric motors.
Jacquez told me there has been “years of work, including by the first Trump administration, that has pointed to this exact case as the worst-case scenario that could happen in an escalation with China.” It stands to reason, then, that experienced policymakers in the Trump administration might have been mindful of forestalling this when developing their tariff plan. But apparently not.
“The lines of attack here are numerous,” Jacquez said. “The fact that the National Economic Council and others are apparently just thinking about this for the first time is pretty shocking.”
And that’s not the only thing the Trump administration is doing that could hamper American access to rare earths and critical minerals.
Though China still effectively controls the global pipeline for most critical minerals (a broader category that includes rare earths as well as more commonly known metals and minerals such as lithium and cobalt), the U.S. has been at work for at least the past five years developing its own domestic supply chain. Much of that work has fallen to the Department of Energy, whose Loan Programs Office has funded mining and processing facilities, and whose Office of Manufacturing and Energy Supply Chains hasfunded and overseen demonstration projects for rare earths and critical minerals mining and refining.
The LPO is in line for dramatic cuts, as Heatmap has reported. So, too, are other departments working on rare earths, including the Office of Manufacturing and Energy Supply Chains. In its zeal to slash the federal government, the Trump administration may have to start from scratch in its efforts to build up a rare earths supply chain.
The Department of Energy did not reply to a request for comment.
This vulnerability to China has been well known in Washington for years, including by the first Trump administration.
“Our dependence on one country, the People's Republic of China (China), for multiple critical minerals is particularly concerning,” then-President Trump said in a 2020 executive order declaring a “national emergency” to deal with “our Nation's undue reliance on critical minerals.” At around the same time, the Loan Programs Office issued guidance “stating a preference for projects related to critical mineral” for applicants for the office’s funding, noting that “80 percent of its rare earth elements directly from China.” Using the Defense Production Act, the Trump administration also issued a grant to the company operating America's sole rare earth mine, MP Materials, to help fund a processing facility at the site of its California mine.
The Biden administration’s work on rare earths and critical minerals was almost entirely consistent with its predecessor’s, just at a greater scale and more focused on energy. About a month after taking office, President Bidenissued an executive order calling for, among other things, a Defense Department report “identifying risks in the supply chain for critical minerals and other identified strategic materials, including rare earth elements.”
Then as part of the Inflation Reduction Act in 2022, the Biden administration increased funding for LPO, which supported a number of critical minerals projects. It also funneled more money into MP Materials — including a $35 million contract from the Department of Defense in 2022 for the California project. In 2024, it awarded the company a competitive tax credit worth $58.5 million to help finance construction of its neodymium-iron-boron magnet factory in Texas. That facilitybegan commercial operation earlier this year.
The finished magnets will be bought by General Motors for its electric vehicles. But even operating at full capacity, it won’t be able to do much to replace China’s production. The MP Metals facility is projected to produce 1,000 tons of the magnets per year.China produced 138,000 tons of NdFeB magnets in 2018.
The Trump administration is not averse to direct financial support for mining and minerals projects, but they seem to want to do it a different way. Secretary of the Interior Doug Burgum has proposed using a sovereign wealth fund to invest in critical mineral mines. There is one big problem with that plan, however: the U.S. doesn’t have one (for the moment, at least).
“LPO can invest in mining projects now,” Jacquez told me. “Cutting 60% of their staff and the experts who work on this is not going to give certainty to the business community if they’re looking to invest in a mine that needs some government backstop.”
And while the fate of the Inflation Reduction Act remains very much in doubt, the subsidies it provided for electric vehicles, solar, and wind, along with domestic content requirements have been a major source of demand for critical minerals mining and refining projects in the United States.
“It’s not something we’re going to solve overnight,” Jacquez said. “But in the midst of a maximalist trade with China, it is something we will have to deal with on an overnight basis, unless and until there’s some kind of de-escalation or agreement.”
A conversation with VDE Americas CEO Brian Grenko.
This week’s Q&A is about hail. Last week, we explained how and why hail storm damage in Texas may have helped galvanize opposition to renewable energy there. So I decided to reach out to Brian Grenko, CEO of renewables engineering advisory firm VDE Americas, to talk about how developers can make sure their projects are not only resistant to hail but also prevent that sort of pushback.
The following conversation has been lightly edited for clarity.
Hiya Brian. So why’d you get into the hail issue?
Obviously solar panels are made with glass that can allow the sunlight to come through. People have to remember that when you install a project, you’re financing it for 35 to 40 years. While the odds of you getting significant hail in California or Arizona are low, it happens a lot throughout the country. And if you think about some of these large projects, they may be in the middle of nowhere, but they are taking hundreds if not thousands of acres of land in some cases. So the chances of them encountering large hail over that lifespan is pretty significant.
We partnered with one of the country’s foremost experts on hail and developed a really interesting technology that can digest radar data and tell folks if they’re developing a project what the [likelihood] will be if there’s significant hail.
Solar panels can withstand one-inch hail – a golfball size – but once you get over two inches, that’s when hail starts breaking solar panels. So it’s important to understand, first and foremost, if you’re developing a project, you need to know the frequency of those events. Once you know that, you need to start thinking about how to design a system to mitigate that risk.
The government agencies that look over land use, how do they handle this particular issue? Are there regulations in place to deal with hail risk?
The regulatory aspects still to consider are about land use. There are authorities with jurisdiction at the federal, state, and local level. Usually, it starts with the local level and with a use permit – a conditional use permit. The developer goes in front of the township or the city or the county, whoever has jurisdiction of wherever the property is going to go. That’s where it gets political.
To answer your question about hail, I don’t know if any of the [authority having jurisdictions] really care about hail. There are folks out there that don’t like solar because it’s an eyesore. I respect that – I don’t agree with that, per se, but I understand and appreciate it. There’s folks with an agenda that just don’t want solar.
So okay, how can developers approach hail risk in a way that makes communities more comfortable?
The bad news is that solar panels use a lot of glass. They take up a lot of land. If you have hail dropping from the sky, that’s a risk.
The good news is that you can design a system to be resilient to that. Even in places like Texas, where you get large hail, preparing can mean the difference between a project that is destroyed and a project that isn’t. We did a case study about a project in the East Texas area called Fighting Jays that had catastrophic damage. We’re very familiar with the area, we work with a lot of clients, and we found three other projects within a five-mile radius that all had minimal damage. That simple decision [to be ready for when storms hit] can make the complete difference.
And more of the week’s big fights around renewable energy.
1. Long Island, New York – We saw the face of the resistance to the war on renewable energy in the Big Apple this week, as protestors rallied in support of offshore wind for a change.
2. Elsewhere on Long Island – The city of Glen Cove is on the verge of being the next New York City-area community with a battery storage ban, discussing this week whether to ban BESS for at least one year amid fire fears.
3. Garrett County, Maryland – Fight readers tell me they’d like to hear a piece of good news for once, so here’s this: A 300-megawatt solar project proposed by REV Solar in rural Maryland appears to be moving forward without a hitch.
4. Stark County, Ohio – The Ohio Public Siting Board rejected Samsung C&T’s Stark Solar project, citing “consistent opposition to the project from each of the local government entities and their impacted constituents.”
5. Ingham County, Michigan – GOP lawmakers in the Michigan State Capitol are advancing legislation to undo the state’s permitting primacy law, which allows developers to evade municipalities that deny projects on unreasonable grounds. It’s unlikely the legislation will become law.
6. Churchill County, Nevada – Commissioners have upheld the special use permit for the Redwood Materials battery storage project we told you about last week.