Nuclear Repairs No Easy Sale as Cheap Gas Hits Utilities
A damaged Florida nuclear plant that spurred a boardroom coup at Duke Energy Corp. (DUK) in July risks getting scrapped unless the power company can justify spending more than $1.3 billion on the costliest-ever U.S. atomic repair.
Duke’s decision, a signpost for utilities from Japan to Belgium considering shuttering reactors, hinges on natural gas. Near-record low prices in the U.S. make new gas-fired generation look more economical than fixing the 35-year-old Crystal River Unit 3 station. The question for Duke, the biggest U.S. power company, is whether to bet gas will stay low for decades.
“If you close that plant down I will have a concern about the dependence on natural gas,” J.R. Kelly, Florida’s Public Counsel, said in a phone interview. He sees the reactor that’s been out of service since 2009 being replaced by gas-fired generation. “That’s what they will build. They’ll have to.”
Volatile fuel prices and increased safety concerns after last year’s meltdown of reactors in Fukushima, Japan, are pushing utilities to reconsider new construction, major repairs and license extensions. Nuclear power represents almost 20 percent of U.S. energy supplies.
Duke’s board ousted then-Chief Executive Officer Bill Johnson hours after acquiring his former company, Progress Energy Inc., and after expressing concern he was prejudiced toward repairing the reactor, which critics have called “Humpty Dumpty” for its cracked concrete shell.
The dispute underscores the stakes for U.S. power companies weighing nuclear investments against falling power prices and risks that plants won’t be relicensed or may close prematurely. Regulators haven’t approved Duke’s plans to pass repair expenses on to clients, and decommissioning costs haven’t been tallied.
Edison International (EIX) faces a similar decision with its 30- year-old San Onofre atomic station near Los Angeles, shut down since January because of leaks and unusual wear to its steam generators.
The surplus of gas-fired power plants in the western U.S. weakens the case for repairing and restarting San Onofre’s twin reactors. “The argument that ratepayers need to keep supporting Grandma lasts for about 15 seconds,” John Geesman, a former California energy commissioner, said in a phone interview. He serves as outside counsel for the Alliance for Nuclear Responsibility, which has lobbied the state to keep that plant idle.
For Florida regulators and consumers, the costs to fix Duke’s reactor may be dwarfed by the risk of becoming overly dependent on a fuel where prices have swung from less than $2 to almost $15 per million British thermal units and back to $2 in the past 11 years.
Gas fueled 62 percent of Florida’s electricity generation in 2011, up from 31 percent 10 years ago, the U.S. Energy Department said on its website.
Officials in Omaha, Nebraska, opted to repair the fire-and- flood-damaged Fort Calhoun Station, a nuclear plant owned by the municipality, to avoid becoming overly dependent on one fuel.
“We have seen coal go up, natural gas go up,” Jeff Hanson, spokesman for the plant’s owner, the Omaha Public Power District, said in a phone interview. “Uranium stays somewhat stable,” he said of the fuel used to derive nuclear power.
Deciding whether to shutter a large power plant isn’t easy for Duke, based in Charlotte, North Carolina, or for Edison of Rosemead, California, and other owners of regulated U.S. utilities.
The rates the utilities charge customers, which are set by state regulators, cover fuel and some repair costs, while providing a mandated return on assets such as plants and transmission lines.
“In that model you’d prefer to repair the nuclear plant because it’s a bigger investment, you’re earning more,” Sam Brothwell, utilities analyst for Bloomberg Industries, said in a phone interview. “But you’ve got to get the regulators to agree. That’s where natural gas is a real challenge because it’s the least-cost option.”
Gas has become the cheapest source of power for much of the U.S. with prices that have tumbled 23 percent from a year ago, and 78 percent from 2008’s peak price of $13.58 per million British thermal units, according to data compiled by Bloomberg.
The all-in cost to produce electricity during the second quarter, including operating and capital expenses, was $71 per megawatt-hour at a combined-cycle gas plant, $82.27 at a coal- fired plant and $101.54 at a nuclear plant, according to data compiled by Bloomberg New Energy Finance.
A gas slump that lasts through the decade, as some industry forecasts suggest, would make “big-ticket” investments in steam generators, reactor vessels or costly capacity upgrades “increasingly difficult to justify,” Brothwell said.
The case is toughest for plant owners operating in deregulated markets, whose capital spending is funded by power sales, not state-mandated rate increases.
Wholesale electricity prices in PJM Interconnection LLC, the largest competitive U.S. power market, have fallen about 10 percent since late April and “seem to be testing historical lows,” Angie Storozynski, a New York-based analyst for Macquarie Capital USA Inc., wrote in a Sept. 4 research note.
Some merchant nuclear plant owners are deferring large projects such as steam-duct and turbine upgrades that would boost plant output by 10 percent or more at a cost of as much as $1,000 per kilowatt, said Mike Granowski, principal with Bridge Strategy Group, a Chicago-based management consulting firm.
Exelon Corp. (EXC) of Chicago decided in 2010 that it was more economical to close its Oyster Creek reactor in Forked River, New Jersey, when its license expired in 2019 than spend as much as $801 million to build a cooling tower demanded by state officials.
Duke’s board faces a more complicated analysis as it decides the best approach to its Crystal River plant, 80 miles (129 kilometers) north of Tampa.
The silo-shaped concrete building that houses the Crystal River 3 reactor cracked in 2009 as crews replaced the steam generators, huge pipe assemblies that transfer heat from the nuclear reactor to power-generating turbines. Once the damaged panel was patched, two other sections cracked in March and July 2011 after workers tightened steel tendons intended to strengthen the structure.
“We’re not joking when we call it the Humpty Dumpty reactor,” Stephen Smith, executive director of the Southern Alliance for Clean Energy, said in a phone interview. “We think they ought to quit throwing good money after bad.”
Duke’s board is waiting to see whether Crystal River’s insurer will pay a portion of costs escalating above 2011 estimates of $900 million to $1.3 billion, Mike Hughes, a spokesman for the company, said in a phone interview. Directors also ordered an independent engineering study of the delamination that has laced about half of the plant’s 42-inch- thick containment structure with cracks.
“We are going to try to make a prudent decision,” James Rogers, Duke’s chairman and chief executive officers, told reporters Aug. 13 after briefing Florida regulators on the plant’s status.
Repairing and refueling Crystal River would cost about $2,000 per kilowatt of generating capacity based on original cost estimates. That’s already “well in excess” of the $1,000- to $1,200-per-kilowatt cost of building a new gas plant, said Granowski, the Chicago consultant.
Duke faces penalties if repairs don’t start this year under the terms of a January agreement with Florida regulators. It would be required to refund as much as $100 million that it has received to buy power from other sources while the plant is offline.
Yet if Duke retires Crystal River, the agreement still allows the power company to earn a return on “all remaining investments” it holds in the plant, according to a company filing.
Duke may decide to hibernate the facility rather than permanently decommission it, Margaret Harding, a nuclear industry consultant based in Wilmington, North Carolina, said in a phone interview. Doing so would give Duke the option of repairing and restarting the plant if gas prices rise.
“My gut is that Duke says, ‘No thanks, no thanks’ to the repair this year, Harding said.
Duke fell 0.6 percent to $64.46 at the close in New York. Edison rose 0.2 percent to $44.43.
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