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Economy

America’s New Nuclear Divide

It’s not about politics. It’s about electricity markets.

An atom and power lines.
Heatmap Illustration/Getty Images

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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Matthew Zeitlin

Matthew is a correspondent at Heatmap. Previously he was an economics reporter at Grid, where he covered macroeconomics and energy, and a business reporter at BuzzFeed News, where he covered finance. He has written for The New York Times, the Guardian, Barron's, and New York Magazine. Read More

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