Nuclear Plants, Old and Uncompetitive, Are Closing Earlier Than Expected

The nuclear industry is wrestling with that question as it tries to determine whether problems at reactors, all designed in the 1960s and 1970s, are middle-aged aches and pains or end-of-life crises.

This year, utilities have announced the retirement of four reactors, bringing the number remaining in the United States to 100. Three had expensive mechanical problems but one, Kewaunee in Wisconsin, was running well, and its owner, Dominion, had secured permission to run it an additional 20 years. But it was losing money, because of the low wholesale price of electricity.

“That’s the one that’s probably most ominous,” said Peter A. Bradford, a former member of the Nuclear Regulatory Commission and a former head of the Public Service Commission in New York. “It’s as much a function of the cost of the alternatives as it is the reactor itself.”

While the other three, San Onofre 2 and 3 near San Diego and Crystal River 3 in Florida, faced expensive repair bills because of botched maintenance projects, “Kewaunee not only didn’t have a major screw-up in repair work, it didn’t even seem to be confronting a major capital investment,” he said.

This is a turnaround because until recently, the life expectancy of reactors was growing. When the Nuclear Regulatory Commission began routinely authorizing reactors to run 20 years beyond their initial 40-year licenses, people in the electricity business began thinking that 60 was the new 40. But after the last few weeks, 40 is looking old again, at least in reactor years, with implications for the power plants still running, and for several new ones being built.

“They were intended to last for as long as they were commercially feasible,” said Robert E. Curry Jr., who was a member of the New York Public Service Commission from 2006 to 2012. But with low gas prices, additional costs imposed after the Fukushima Daiichi accident of March 2011, and “the general mistrust of nuclear by anyone who saw ‘The China Syndrome,’ ” commercial feasibility now is evidently shorter, he said.

Even if the economics do not result in retirements, they do mean setbacks. Exelon, the nation’s largest nuclear operator, set out a few years ago to invest $2.3 billion in its existing reactors and raise their generating capacity by 1,300 megawatts, a little more than one new reactor would generate. But after completing about a quarter of the plan, it dropped the rest, and said it would pay its suppliers $100 million in penalties for the cancellation, because the economics were no longer favorable.

Christopher M. Crane, the chief executive, said that Exelon had no plans now to retire any reactors but that the company would continue to review conditions, including low wholesale prices for electricity, to see if early shutdowns were needed.

Oyster Creek, an Exelon reactor in Forked River, N.J., is the oldest in the country, having opened in 1969. It received a 20-year license extension in 2010, but Exelon promised to shut it by the end of 2019 in exchange for an exemption from some rules governing the discharge of hot water from the plant. It might not make it to 2019, though. At San Onofre, the owners were faced with the need for a big new investment for repair, and calculated not only the price but the number of years of life remaining over which they could recoup their investment. The same could happen at Oyster Creek.

Two to watch are Vermont Yankee, in Vernon, just north of the Massachusetts border, and Indian Point, in Buchanan, N.Y., 30 miles up the Hudson River from New York City. The states of Vermont and New York are seeking to close them. If they remain profitable, the owner of all three units, Entergy, seems likely to fight tooth and nail to keep them open, but Vermont Yankee’s profitability does not seem certain. It could join plants like Maine Yankee, or Zion, near Chicago, in retirement and decommissioning.

Such is the fate of all old power plants. As the Nuclear Energy Institute, the industry’s main trade association, pointed out when San Onofre closed, of the power plant retirements since 2010, 41 percent were coal and 33 percent were natural gas. Ten percent were nuclear. Old power plants lead conditional existences; they may not survive new environmental rules or other circumstances that require expensive retrofits.

The difference is that gas plants continue to be built, and so do a few coal plants. There was a gap of 30 years in new nuclear plant construction, which ended this year, but only four plants, two twin-reactor installations, have broken ground. A fifth, left for dead in the 1980s, is being revived. While utilities in the last few years have announced plans for more than a dozen new reactors, beyond the five now under construction only another four or so seem possible in the next few years.

And all the others are getting older.

Nuclear Power’s Future May Hinge on Georgia Project

But something else is at stake with the reactors called Vogtle 3 and 4: the future of the American nuclear industry itself.

The Alvin W. Vogtle nuclear power plant near Augusta is using a new plant design, a new construction method and a new system of nuclear regulation for what the industry says is a faster, better and cheaper system that will lead the way for a new generation of reactors.

Until recently, a new reactor construction project had not been started in the United States for 30 years, and now Vogtle and a similar project in South Carolina, V.C. Summer 2 and 3, are supposed to provide the answer to nuclear power’s great questions: What does a new reactor cost? With the price of natural gas near historic lows, can it even be worthwhile?

As the current generation of reactors moves toward retirement, the two projects may be the industry’s last best hope.

“Everybody’s watching the construction of that plant,” said Barry Moline, executive director of the Florida Municipal Electric Association, speaking of Vogtle. Several association members are considering investing in a nearly identical plant proposed by Florida Power and Light in Miami. Mr. Moline said of Vogtle’s builders, led by Georgia Power, “If they can do it, that will be the model.”

And if they can’t, it could years before anybody thinks of trying again. The new designs are supposed to be 10 times less likely to have an accident and be easier to operate, but if they cannot be built roughly on time and on budget, then nuclear power will have trouble in the era of plentiful natural gas and emerging technologies like wind. Nuclear power could become a bypassed technology — like moon landings, Polaroid photos and cassette tapes.

Executives at Southern Company, Georgia Power’s corporate parent, say they are eager for the challenge. “It takes leadership to do something like this,” said Joseph A. Miller, known as Buzz, Southern’s vice president for nuclear development.

Southern, one of the biggest utilities in the United States, raced to grab incentives offered by Congress to restart the nuclear construction business and to try out a licensing system devised by the Nuclear Regulatory Commission to avoid a repeat of the experience of the 1970s and ‘80s.

In those decades parts of plants were built, ripped out and rebuilt because of design and regulatory problems, leading to ruinous costs. Examples sit across the muddy construction site: Vogtle 1 and 2, which opened in 1987 and 1989, cost $8.87 billion. When they were proposed in 1971 the estimated cost was $660 million.

For Vogtle 3 and 4, the company submitted a license application with a design described as nearly complete and received an operating license when construction had barely started, contingent on building exactly what it said it would.

The older plants, in contrast, were built by welders and pipe fitters and electricians who were working from incomplete plans that were conflicting, vague or inadequate to meet regulatory standards.

In a second innovation, Southern chose a system in which large sections of the plant would be prefabricated in multiton sections, shipped to the site and welded together into gigantic modules, then loaded into place by the world’s largest crane.

But with construction now roughly one-third complete, it is clear that much is not going as planned, and that the schedule — which is closely linked to cost because of growing interest expense on the incomplete asset — has slipped by at least 14 months and possibly more.

Still, all is not lost. Some of the changes since the company committed to the project seven years ago have helped it along; interest rates are at historic lows and the price for labor and materials has been held down by recession.

San Onofre Nuclear Plant in California to Close

The owners of the San Onofre nuclear power plant in Southern California, which has been shut since January 2012, said on Friday that they would close it permanently because of uncertainty over when it could be reopened.

The two reactors at San Onofre had not run since a small amount of radioactive steam escaped from new tubes damaged by vibration and friction. Coming months after the Fukushima Daiichi meltdown in Japan, the event prompted a wave of public opposition and set off a legal and regulatory battle that included Southern California Edison, the Nuclear Regulatory Commission and Mitsubishi Heavy Industries, which manufactured the parts that leaked.

Those parts, called steam generators, cost more than $600 million. In the end, uncertainty over the plant’s fate “was not good for our customers, our investors, or the need to plan for our region’s long-term electricity needs,” said Theodore F. Craver Jr., chief executive of the utility’s parent company, Edison International.

The decision delighted nuclear opponents. “I approach today with a good deal of joy,” said S. David Freeman, who shut down construction on several reactors when he ran the Tennessee Valley Authority, and who ran the Sacramento Municipal Utility District after it retired the Rancho Seco nuclear plant two decades ago.

“I think this is a step in the right direction, another move toward the renewable revolution that is under way in the state of California,” Mr. Freeman said, adding that closing the reactors opens up the market to use the renewable power that will follow. For now, though, the replacement power source is natural gas.

The nuclear industry has had a difficult year as it tries to compete with cheaper, abundant natural gas. San Onofre’s two reactors are the third and fourth reactors to be retired so far this year in the United States.

“It’s no secret that power markets have been radically changed by the development of shale gas,” said John Reed, an investment banker who specializes in nuclear reactors. “That changes the economics of any other power supply option, including nuclear.”

Dominion shut its reactor in Wisconsin in May because of unfavorable economics, and Duke said in February that it would not restart Crystal River 3 because mechanical problems were too expensive to fix.

The loss of San Onofre has already pushed up electricity prices in Southern California, to about $4.15 a megawatt-hour higher than prices in Northern California. Those higher prices are an inducement to developers to build new generation, either natural gas or renewable energy, according to Marie Rinkoski Spangler, an electricity analyst at the Energy Department’s Energy Information Administration.

Ms. Rinkoski Spangler said that since June 2012, California has added slightly more generating capacity than it will lose with the retirement of the reactors, in the wrong places.

“Geography really matters,” she said. “The generation itself is not enough, because of where San Onofre sat” near Los Angeles and San Diego.

At the California Independent System Operator, the company that runs the power grid in most of the state, Steve Berberich, the chief executive, said that most of the replacement power had come from natural gas, and that if California’s goal is to reduce greenhouse gas emissions per kilowatt-hour, “you’re moving in the wrong direction.”

But in the longer term, he said, retiring San Onofre would encourage the replacement of older power plants with newer ones that would produce more electricity with the same amount of fuel. And the newer ones could increase and decrease their output faster, he said, making them useful to balance a system with a lot of wind and solar generation, which is highly variable.

San Onofre 2 and 3 entered commercial operation in August 1983 and April 1984. A third reactor was mothballed in 1992.

Many nuclear plants around the country have won permission from the Nuclear Regulatory Commission to run 20 years beyond their initial 40-year licenses, but in a conference call with reporters, Mr. Craver of Edison International said that the prospects for license renewal were uncertain, following the three meltdowns at the Fukushima Daiichi plant in March 2011, and the demand by regulators for a re-evaluation of San Onofre’s vulnerability to earthquake.

Edison had been seeking to restart one of the units at 70 percent power, a level it thought the steam generators could tolerate, but when plant opponents persuaded a panel of three administrative law judges at the Nuclear Regulatory Commission that this would require a public hearing, the company concluded that the proceedings could stretch to the end of next year or longer. Operation and maintenance expense at the plants, which employ 1,500 people are roughly equal whether it is running or not, he said, and if the plant could not reopen by December, retiring it would be cheaper.

The company has $2.7 billion saved up for decommissioning, which is about 90 percent of what is required, he said. Edison shares ownership with San Diego Gas & Electric, which owns 20 percent, and the city of Riverside, which owns 1.79 percent.

Edison has about $2.1 billion invested in the plant, the fuel and related assets. Division of costs between Edison’s shareholders and ratepayers, its insurers and Mitsubishi Heavy Industries, which supplied the heat exchangers, has not been determined.

As for the plant’s workers, the closure will be felt in the area. “When 1,100 people lose their jobs, there will certainly be an impact,” said Bob Baker, the mayor of the nearby city of San Clemente. “San Onofre changed San Clemente when it opened, and it’s going to change San Clemente now that it’s closing.”

Business Briefing | Company News: A Second Nuclear Plant in Turkey Is Approved

The Civil War marked the end of the age when pitched battles determined the outcome of a conflict.

What recent evidence of cannibalism at Jamestown tells us about the earliest English settlements.

Japan’s Cleanup After a Nuclear Accident Is Denounced

But much of the work at the Naraha-Minami Elementary School, about 12 miles away from the ravaged Fukushima Daiichi nuclear power plant, tells another story. For eight hours a day, construction workers blast buildings with water, cut grass and shovel dirt and foliage into big black plastic bags — which, with nowhere to go, dot Naraha’s landscape like funeral mounds.

More than a year and a half since the nuclear crisis, much of Japan’s post-Fukushima cleanup remains primitive, slapdash and bereft of the cleanup methods lauded by government scientists as effective in removing harmful radioactive cesium from the environment.

Local businesses that responded to a government call to research and develop decontamination methods have found themselves largely left out. American and other foreign companies with proven expertise in environmental remediation, invited to Japan in June to show off their technologies, have similarly found little scope to participate.

Recent reports in the local media of cleanup crews dumping contaminated soil and leaves into rivers have focused attention on the sloppiness of the cleanup.

“What’s happening on the ground is a disgrace,” said Masafumi Shiga, president of Shiga Toso, a refurbishing company based in Iwaki, Fukushima. The company developed a more effective and safer way to remove cesium from concrete without using water, which could repollute the environment. “We’ve been ready to help for ages, but they say they’ve got their own way of cleaning up,” he said.

Shiga Toso’s technology was tested and identified by government scientists as “fit to deploy immediately,” but it has been used only at two small locations, including a concrete drain at the Naraha-Minami school.

Instead, both the central and local governments have handed over much of the 1 trillion yen decontamination effort to Japan’s largest construction companies. The politically connected companies have little radiological cleanup expertise and critics say they have cut corners to employ primitive — even potentially hazardous — techniques.

The construction companies have the great advantage of available manpower. Here in Naraha, about 1,500 cleanup workers are deployed every day to power-spray buildings, scrape soil off fields, and remove fallen leaves and undergrowth from forests and mountains, according to an official at the Maeda Corporation, which is in charge of the cleanup.

That number, the official said, will soon rise to 2,000, a large deployment rarely seen on even large-sale projects like dams and bridges.

The construction companies suggest new technologies may work, but are not necessarily cost-effective.

“In such a big undertaking, cost-effectiveness becomes very important,” said Takeshi Nishikawa, an executive based in Fukushima for the Kajima Corporation, Japan’s largest construction company. The company is in charge of the cleanup in the city of Tamura, a part of which lies within the 12-mile exclusion zone. “We bring skills and expertise to the project,” Mr. Nishikawa said.

Kajima also built the reactor buildings for all six reactors at the Fukushima Daiichi plant, leading some critics to question why control of the cleanup effort has been left to companies with deep ties to the nuclear industry.

Also worrying, industry experts say, are cleanup methods used by the construction companies that create loose contamination that can become airborne or enter the water.

At many sites, contaminated runoff from cleanup projects is not fully recovered and is being released into the environment, multiple people involved in the decontamination work said.

Makiko Inoue contributed reporting from Tokyo.

This article has been revised to reflect the following correction:

Correction: January 8, 2013

An earlier version of this article misstated the name of the construction company in charge of the cleanup of the city of Tamura. It is the Kajima Corporation, not Kashima. The article also referred incorrectly to Fukushima Prefecture. It contains 100 square miles of the more heavily contaminated areas; the prefecture itself is not 100 square miles. And the article misstated the year that the Japan Atomic Energy Agency announced it was soliciting new decontamination technology. It was October 2011, not 2012.

Europe Nuclear Reactors Need Fixes, Report Says

The scale of the problems detailed in the draft report, as well as the size of the expected repair bill, may amplify public concerns about the safety of nuclear power on the part of Europeans, who are already deeply divided over the technology and whose governments still zealously guard control over energy policy at the national level.

The European Commission undertook the safety review of its nuclear plants after the March 2011 earthquake and tsunami in Japan, which led to the disaster at the Fukushima Daiichi plant.

Part of the assessment was the performance of so-called stress tests, which are meant to assess how a nuclear facility would fare in various kinds of failures and crises. National experts conducted the stress tests in conjunction with the commission’s advisory group on nuclear safety. The tests identified the need for “hundreds of technical upgrade measures,” the draft report says.

The two biggest previous civilian nuclear accidents — at Three Mile Island outside Harrisburg, Pa., in 1979, and at Chernobyl, Ukraine, in 1986 — were both followed by similar scrutiny, and agreements were reached on extensive new safety measures. But the draft report notes that “even today, decades later, the implementation of those measures is still pending” in some of the union’s member countries.

Vulnerabilities found by the commission and identified in the draft report include a situation at four reactors in Finland and Sweden, where if the cooling systems failed or all electric power was lost, the operators would have less than an hour to restore safety functions before catastrophic damage took place. The draft report says that 10 reactors in countries including Spain, France and the Czech Republic lack adequate equipment to detect earthquakes.

Most of the upgrades called for in the draft report involve making European nuclear plants better able to withstand quakes, flooding and the loss of primary cooling — the factors that combined to devastating effect at the Fukushima Daiichi plant. The draft report also says that rules ensuring the independence of national nuclear safety regulators “are minimal.” The European Union’s energy commissioner, Günther Oettinger, is expected to announce plans on Thursday for unionwide legislation meant to improve reporting and protect the regulators’ independence.

Mark Breddy, a spokesman for Greenpeace European Unit, the environmental advocacy organization, said: “Cozy relationships between nuclear operators, regulators and politicians were pivotal to aggravating the Fukushima disaster. The situation isn’t much better in Europe.” Given those relationships, he said, he questioned whether the European Commission’s stress tests were as thorough and as impartial as they should have been.