Cheap natural gas, high construction costs and a disaster in Japan have combined to dim prospects for a resurgence in nuclear power — especially in Texas’ unregulated market where utility companies must bear all of the financial risk of building new plants.
Because new technology has unlocked natural gas in shale formations, its price has dropped and its use as a power generation fuel has grown.
“The shale gas situation is making it difficult for utilities to justify the cost of a new nuclear plant,” said Clayton Scott, chief nuclear officer for Invensys, a global technology company that provides control and safety systems to the power industry.
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Despite the challenges, the government predicts that nuclear power will have a place in the nation’s energy mix for decades. Advocates tout its lack of greenhouse gas emissions, and market analysts note that natural gas isn’t likely to stay cheap indefinitely.
Two nuclear power plants operate in Texas, providing about 12 percent of the power on the state’s electric grid. NRG Energy’s South Texas Project in Matagorda County, about 90 miles southwest of Houston, has two units with a combined capacity of 2,700 megawatts. Luminant’s Comanche Peak Nuclear Power Plant in Somervell County, about 40 miles south of Fort Worth, has a capacity of 2,400 megawatts from its two units.
NRG is pursuing a permit for a future expansion at South Texas, but has no near-term construction plans. Exelon, which owns the largest nuclear fleet in the country, has dropped plans for an entirely new plant in Victoria Ccounty.
New nuclear plants can take almost a decade to permit and build, and are costlier than other options.
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Construction of nuclear generation capacity costs $3,900 to $4,400 per kilowatt, according to the Electric Power Research Institute, an industry research organization based in Palo Alto, Calif.
At the middle of those ranges, a nuclear plant the size the South Texas Project would cost about $11 billion, while 2,700 megawatts of natural gas generation would cost about $3 billion.
The financial benefits of nuclear power come to life, however, as soon as the plant is turned on.
“Nuclear energy resources typically generate electricity very cost effectively, so they tend to operate at their maximum operating point whenever they are available,” said Warren Lasher, head of planning for the Electric Reliability Council of Texas, which manages the grid for about 90 percent of the state. “When nuclear plants come off of a maintenance outage, they ramp up to their maximum output and they stay there.”
These relatively low operating costs and the resulting price stability for nuclear-generated wholesale electricity have prompted new nuclear plant construction in Georgia, South Carolina and Tennessee.
Unlike their counterparts in Texas, however, electric utilities in those states operate in a regulated environment, meaning their rates are set under laws that allow them to recapture some construction costs from ratepayers before operations begin.
“One of the ways they are dealing with the high capital costs is that they are getting paid as they go,” said Tony Pietrangelo, senior vice president and chief nuclear officer for the Nuclear Energy Institute, a Washington-based trade association.
The pay-as-you-go approach also applied in Texas when its existing nuclear plants were built in the 1980s, easing the burden of financing. But the deregulated market in place since the early 2000s prevents utilities from billing customers for future power generation.
That means companies must design, finance and build new plants before deriving any income from them, and without knowing what rates the market will bear by then.
That discourages new nuclear construction in the near term, because of the high up-front costs.
“My own view is that at least until the end of this decade, it would be impossible for a non-regulated power generator to contemplate a nuclear new build,” said Bill Hunter, a senior utilities analyst with Moody’s. “Even in the next decade, the folks who will be building nuclear power plants will be regulated utilities. ”
Investors also are concerned about how regulatory uncertainty could affect costs — particularly since the 2011 Japanese earthquake, tsunami and Fukushima Daiichi plant meltdown brought renewed attention to nuclear power’s potential for disaster, even though the probability of such events is low.
Regulatory costs factored into Southern California Edison’s decision earlier this month june to close permanently its San Onofre nuclear plant in San Diego, which hasn’t generated power since a radiation leak in early 2012.
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Even so, the U.S. Energy Information Administration projects that nuclear plants will generate 17 percent of the nation’s total electricity by 2040 — just slightly lower than its 19 percent share now — based on the expectation that most existing plants will receive the 20-year renewal of their licenses.
The United States has 103 operating nuclear plants, and owners are investing heavily in preventive maintenance and modernized safety systems to ensure the plant’s health for decades to come.
“The plants that exist will continue to run,” said Dennis Koehl, CEO of the South Texas Project, which is owned jointly by NRG Energy and by municipal utilities CPS in San Antonio and Austin Electric in the state capital.
He said the owners spend tens of millions of dollar a year maintaining and replacing plant equipment and investing in new technology. “We do ongoing surveillances on the equipment, making modifications to improve the plant’s performance,” Koehl said. “Our overriding priority is to ensure the continued safe and reliable operation of the facility.”
The two South Texas Project units are licensed to operate until the end of the 2020s, and their owners have applied for a 20-year renewal. The Nuclear Regulatory Commission has approved more than 90 percent of license renewals, and South Texas operators anticipate approval sometime in the next year.
The stability of nuclear power operating costs could mitigate the effects of future rises in natural gas prices.
Because prices are more volatile for natural gas than for nuclear fuel, gas generators are hesitant to enter into contracts locking in long-term wholesale rates for the power they provide retailers.
That might drive Texas retailers — which also operate in a competitive, deregulated market — toward longer-term deals for nuclear power, said Bernie Neenan, an energy economist with the Electric Power Research Institute.
“As the spot market prices keep moving up, at some point retailers will break and say, ‘I can’t risk buying all my needs on the spot market,’?” Neenan said.
But in a country awash in natural gas that is hovering around $4 per million British thermal units — less than a third of its cost just five years ago — it might be some time before prices rise enough to assure generation companies they can recoup costs of building new nuclear plants.
“It is not an accident that the only place new plants are being built are places where all the risk is being placed on the ratepayer, and not on the utility,” said Jim Marston, regional director of the Texas office of the Environmental Defense Fund. “That tells me something about how utilities think about nuclear power. If it is utility money at risk, utilities have not been willing to go forward.”
Moody’s Hunter, however, believes that higher power prices over the longer term, combined with the need for fuel source diversity, eventually will encourage a move back to investing in nuclear.
“In the next decade, there will be more activity, because you can’t run a whole country on one fuel source,” Hunter said. “Utilities can’t just build more natural gas plants, because it will leave them more exposed when prices go up.”