Nuclear power: CO2 fix or cost disaster?

By Kristi E. Swartz | 02/04/2022 07:07 AM EST

Surging gas prices are resurfacing a debate about how much nuclear will play a role in the U.S. electricity mix in coming decades.

Two new reactors are under construction at Plant Vogtle in Georgia.

Two new reactors are under construction at Plant Vogtle in Georgia. The nuclear power industry is facing questions about its ability to compete with natural gas as the U.S. generation mix evolves. Georgia Power

President Biden’s plan to decarbonize the U.S. electricity sector by 2035 could give a boost to nuclear power, but that may hinge on two key questions: Can carbon targets really incentivize the technology, and can it compete cost wise with natural gas?

It’s a debate that is resurfacing, considering recent surging prices of natural gas.

Yet industry hasn’t answered whether nuclear will be more economic for producing power, especially after costs for two new reactors at Plant Vogtle in Georgia skyrocketed. The actual costs of 75 of the more than 90 existing nuclear power reactors in the U.S. exceeded the initially estimated costs of the units by over 200 percent, according to the U.S. Department of Energy.


There are many facets of the cost question — existing nuclear plants in competitive markets face economic challenges that could force them to close early, saddling operators with stranded costs and removing emissions-free electrons from the grid. Meanwhile, no large, baseload reactors are on the table. The industry is working to develop smaller, next-generation reactors by the next decade, but the fate and final costs of projects are uncertain.

“There doesn’t seem to be, in the near term, a big thing that’s going to be pushing” nuclear, said Paul Patterson, a utility analyst with Glenrock Associates LLC. Whether the nuclear industry builds new reactors could help shape the electricity mix for decades. Falling renewable energy costs and higher gas prices may also influence investment decisions for nuclear in unexpected ways.

In comparison to gas, nuclear can tout lower and more stable fuel costs, but the capital costs are significantly higher. Information from the U.S. Energy Information Administration shows nuclear fuel costs ranging from roughly one-third to as low as one-quarter of those of natural gas between 2010 and 2020. Overall, the costs of nuclear generation, including operations, have fallen 35 percent since 2012, according to the Nuclear Energy Institute (NEI).

But Southern Co.’s Vogtle expansion project hasn’t helped the case for baseload nuclear. The project, which was supposed to lead a resurgence of larger reactors in the 2000s, remains the only major nuclear power construction project in the United States. Vogtle’s price tag is twice an earlier $14 billion budget, and the project is more than seven years behind schedule.

Southern and a South Carolina electric company were first out of the gate to build the new wave of baseload reactors, but more than a dozen others were in the queue nationwide. Plummeting natural gas prices from fracking led other electric companies to pull back on their nuclear plans. Since then, more than one big electric company has shelved its plans to build large reactors using similar technology because of the litany of troubles at Vogtle.

The industry instead is turning to new nuclear technologies that developers say are safer and more efficient, both of which will drive down costs. In other cases, electric companies have asked federal regulators to extend the operating licenses of their large reactors to run longer.

As a result, money in the bipartisan infrastructure law points to two key areas: keeping economically struggling reactors alive and pushing new Generation IV technologies out the door so they can be ready for electric companies to connect to the grid by the next decade.

To be clear, there’s $1.2 billion in the package for existing, but troubled, reactors and more than $20 billion for the Energy Department to aid clean energy demonstration technologies, including advanced nuclear.

That means the industry is once again banking its future on technologies that have yet to be built — or proven — at scale. Despite all of the promises that new reactors will be cheaper because of their smaller size and more efficient technology, there’s not a full track record to prove it either way.

The next generation

Generation IV reactors include thermal, molten salt and fast reactors. Developers are billing them as smaller, safer, more efficient and able to operate longer than large, baseload ones.

Just two states — Idaho and Tennessee — are considering Generation IV reactors right now, but others are expected to follow.

These smaller reactors also are more agile, enabling them to be paired with renewables to stabilize the grid. Improved safety and efficiency means they also should be cheaper, possibility eliminating the industry’s biggest headache.

NEI, an industry trade group, sees “great opportunities for progress” in new nuclear projects, as opposed to older, traditional baseload ones, according to Marc Nichol, NEI’s senior director for new reactors.

“Already we are seeing significant customer interest in SMRs,” or small modular reactors, Nichol said in an email to E&E News.

Yet it’s unclear whether SMRs will face some of the same cost challenges as traditional reactors.

In the past, the higher price tag for nuclear in comparison to expectations was tied to safety regulations, which are the most stringent of all power plants. What’s more, if any work needs to be redone to meet strict codes, that pushes out the deadline to finish the plant.

The longer it takes to get it right, the more expensive the reactors become.

“There are so many concerns about radioactive material, etc., so that’s what drives much of the cost,” Glenrock’s Patterson said. “You don’t have the same issues associated with regulations for other power plants, understandably so.”

With SMRs, federal nuclear regulators still must sign off on stringent safety regulations, though proponents argue that the reactors are inherently safer because of their smaller size.

A group of former nuclear regulators in the United States, Germany and France argued last month that nuclear isn’t safe, clean or smart.

It’s more expensive than renewables in terms of producing energy and mitigating carbon dioxide, even accounting for costs such as pairing renewable energy with storage, according to the group, which also includes a former secretary to a United Kingdom radiation protection committee.

The former regulators said nuclear is unlikely “to make a relevant contribution to necessary climate change mitigation” that’s needed by the 2030s.

The industry counters that reactors have long lives, low operating costs and a relatively nonvolatile fuel price. The rise in oil and natural gas prices also gives nuclear a boost, according to clean energy think tank ClearPath.

“There’s a global reawakening that nuclear has got to be part of the solution. … There’s nothing like an energy crisis to make nuclear look really good,” said Rich Powell, CEO of ClearPath.

Carbon taxes and economics

A key factor for where nuclear may go in coming years lies with climate policies.

For example, roughly half of the nation’s reactors will be up for license renewal in the next two decades, according to NEI. In Michigan, the Palisades reactor is scheduled to close this year, and in California, the Diablo Canyon plant will be shuttered by 2025, the nuclear group said. Those reactors total more than 3,000 megawatts, NEI said.

“Premature plant shutdowns would constitute a major blow to state economics and emission-reduction programs,” NEI said on its website.

A November 2021 reportfrom the U.S. Energy Information Administration found that a federal carbon tax would lead to less nuclear capacity being removed from the grid in the form of retired units. In fact, more capacity could be added.

Marilyn Brown, professor of sustainable systems at Georgia Tech’s school of public policy, said her department uses the same model and extends it to include higher CO2 tax levels. The result leads to more nuclear on the grid but not until 2045, Brown said.

Many electric companies deem reactors as critical to meeting their carbon-neutral goals, many of which target 2050.

Utilities often say they can get 80 percent of the way there by taking conventional steps such as shutting down any remaining coal plants and adding gobs of renewable energy. Technologies like next-generation nuclear, hydrogen and storage are needed to bridge the 20 percent gap, company executives have said.

Timing also is critical. The more quickly electric companies need to put more emissions-free generation on the grid, the more expensive it’s going to be, according to utility executives.

“Economics is a driving factor when building these new nuclear technologies with much simpler designs to manufacture and construct,” said Nichol. “It’s proven that costs go down with sustained programs of new nuclear projects, which is where we see great opportunities for progress in the U.S.”

Not everyone sees advanced nuclear, including small reactors, as the best option, however.

“The Biden administration has made clear that advanced nuclear power can and should play a role — perhaps one day a substantial one — in its efforts to achieve 100% carbon-free generation by 2035. We would characterize this position as pragmatic greening: centrist proposals that deviate from progressive orthodoxy that generally supports non-hydro renewable power over nuclear,” Tim Fox, a vice president and research analyst with ClearView Energy Partners LLC, in an email to E&E News.

Lessons from Georgia

The Vogtle project in Georgia continues to be shorthand for nuclear expansion in the U.S., in part because it’s more common to hear policymakers debate nuclear retirements than massive new reactors.

As the first set of reactors to be built in the U.S. in nearly three decades, Vogtle is the most recent frame of reference. The almost $30 billion price tag overshadows the project’s achievements, according to engineers and analysts working with the Georgia Public Service Commission staff.

Officials from Southern frequently argue that Vogtle’s AP1000 reactors will be economic in the long run — 60 to 80 years — when compared to natural gas forecasts. The five state utility regulators are on board with that statement as well.

“So some of the design requirements are very, very strict and very unique to nuclear installations. That’s kind of what helps make these plants so robust. That’s why they operate 24/7 for 60, 80 years,” said Southern Nuclear CEO Stephen Kuczynski at a November hearing about Vogtle.

But this winter, members of the Georgia PSC’s advocacy staff said the electric company is wrong.

“The company grossly under-estimated the costs of Vogtle 3 and 4 in its filings and testimony to the commission during at least the first 12 years of the project,” wrote Tom Newsome, Philip Hayet and Lane Kollen — PSC staff and consultants — in testimony filed with Georgia utility regulators on Dec. 1.

Until the reactors start up, the project cannot receive highly coveted federal production tax credits, which had to be extended past the December 2020 deadline when it became clear that Vogtle wouldn’t be finished by then (Energywire, Feb. 12, 2018).

The tax credits, federal loan guarantees and customer payments covering Vogtle’s costs were reasons that Georgia Power argued it would be cheaper to build nuclear in the long run.

The PSC staff and consultants said that’s not the case anymore, even with looking at financial models that forecast natural gas as high as $20 a ton and carbon prices at $10 a ton.

“Carbon dioxide emissions charges to not make the units economic, and the units are still significantly uneconomic versus alternative combine-cycle generation,” they wrote.

The two reactors at Vogtle are so close to the finish line that the PSC’s advocacy staff said it’s more economic to finish the project because, at this late stage, the costs are going down.

But the economic benefit is small because of how much it has cost to build the reactors so far, the PSC staff and economic consultants said.

“It’s jaw-dropping,” said Liz Coyle, executive director of Georgia Watch, a consumer advocacy group.

Gas and renewables

Ultimately, the trajectory of nuclear will directly affect how wind, solar, batteries and fossil fuels are used in the coming decades.

Coyle pointed out that while the cost of Vogtle has doubled during the seven-year delay, the price of renewables, including storage, has dropped. Going forward, she argues that Georgia Power should compare the cost of planned generation with not only combined-cycle natural gas but also with renewable options such as utility-scale solar and long-term agreements to buy wind power.

“This argument that, ‘Well, it’s reliable, it’s low-cost, it’s carbon-free,’ then why are we still comparing it to combined-cycle natural gas?” Coyle said. “There are now significantly more cost-effective renewable energy options than any of us anticipated back in the day when Vogtle 3 and 4 were certified.”

Southern remains an unwavering proponent of nuclear. The company announced plans in November to build a small, experimental nuclear reactor in Idaho using technology from TerraPower (Energywire, Nov. 19, 2021).

The TerraPower Natrium demonstration plant is being partially financed by a Department of Energy public-private partnership that is a 50-50 cost share for up to $4 billion. The project is using high-assay low-enriched uranium (HALEU), which developers argue will let smaller reactor designs have longer operating cycles and increased efficiency.

“The demonstration project will validate our construction approach, establish our supply chain, build our fuel fabrication facility, and help encourage domestic HALEU enrichment capabilities,” TerraPower said in an email to E&E News. “This will significantly reduce future costs for additional projects.”

Southern isn’t the only power provider looking ahead.

The Tennessee Valley Authority, which gets more than 40 percent of its electricity from nuclear power, wants to build a small modular reactor at the Clinch River site near Oak Ridge, Tenn.

The federal agency is also partnering with California-based Kairos Power LLC to give design expertise as well as guidance in securing a federal license for a 15-MW demonstration fluoride salt-cooled high-temperature reactor (Energywire, June 17, 2021).

TVA CEO Jeff Lyash has been vocal about wanting the federal government’s help in TVA’s potential SMR project, a cluster of smaller reactors that would be more easily dispatchable and incorporated in a modernized grid that supports distributed generation as well as other next-generation reactors.

“Because if we don’t have that line of sight, we need to go in another direction, because we need to go 10 years out,” he said in June, referring to the long-term planning, licensing and construction process needed for nuclear projects.

The Energy Act of 2020 authorized two advanced reactor demonstration projects as well as money for fusion research. The infrastructure law funds a series of clean energy demonstration projects such as advanced nuclear and sets aside money for a Department of Energy credit program meant to be a lifeline for struggling reactors.

A bipartisan bill in the House would waive Nuclear Regulatory Commission licensing fees for advanced reactors (E&E Daily, Dec. 9, 2021).