|Image Source: Smart Animation by Real Illusion|
The dates, Nov 18 for Unit 2, and Dec 31, for Unit 3, are fill in the blanks information provided by Southern California Edison (SCE) to the California Independent Systems Operator (Calif ISO), which manages the state's power grid.
The rapid response from the utility to get the story right is an effective communication strategy and puts to rest claims by anti-nuclear groups that rival those of circus barkers who advertise the presence of dancing giraffes in an effort to sell tickets to a sideshow.
Jannifer Manfre,a spokesperson for SONGS, said in a clarification statement that the dates are "placeholders" for planning purposes only. In fact, state energy officials are making contingency plans in case neither reactor at SONGS returns to service in 2013.
According to Manfre, SCE is required to provide the information but also says "they are not forecast or restart dates."
Calif ISO spokesperson Stephanie McCorkle told wire services that the dates provided by SCE are required for planning purposes but are not firm dates for restart. She said that the utility will only have that information once the NRC gives its approval.
SCE got in hot water with the NRC earlier this year when its CEO provided similar information at an investor briefing. The regulatory agency got testy with SCE thinking that the utility was getting out in front of its headlights. The NRC has told SCE it cannot restart either reactor until the agency is convinced the utility has completely addressed the problems with the steam generators. That includes identifying all the problems and making repairs. Only then will the NRC make a determination that the reactors can be safely restarted and operated by the utility.
Potential for a full head of steam?
"To forecast dates is inconsistent with prudent decision making," Craver said.
Additionally, Craver said the two reactors may never operate at full power again unless the utility replaces the damaged steam generators it has now.
The reason for this statement is that Mitsubishi Heavy Industries (MHI) incorrectly calculated the rate and pressure of steam moving through the equipment. In fact, the steam was found by SCE and the NRC to be moving through the tubes at two-to-three times the numbers provided by MHI which were used to design the units. The challenge for SCE is to figure out how much steam can realistically be pushed through the tubes without the risk of leaks. That number will determine the power level for the reactors and the amount of electricity the utility can produce for customers.
Craver clarified that Unit 2 may be able to restart sooner than Unit 3 because steam tube problems are much less extensive there. Unit 3 has problem tubes and damaged tubes. He said Unit 3 will need more repairs to prevent tube-to-tube wear. Even if Unit 2 is restarted, it will have to be shut down midway through the fuel outage cycle for inspections. That's an expensive extra step due to the costs and the fact the utility isn't generating electricity, or revenue, during the extra outage.
In terms of exploring all options, Craver said SCE is looking at engineering options for what repairs, if any, would allow the reactors to operate at full power. While SCE has plugged a combined total of more than 1,300 tubes in the steam generators for Units 2 & 3, neither has reached the threshold of degraded power from having too many plugged tubes.
Putting costs in perspective
Craver said another $25 million is the estimate of new spending to restart Unit 2. He did not provide details on what work scope is associated with that number and did not provide an estimate of costs associated with repairing and restarting Unit 3.
A future financial issue for SCE is that the California Public Utility Commission may initiate a review of the revenue associated with current rates, which assume the reactors are operating with a full head of steam. SCE has spent $117 million so far on replacement fuel for non-nuclear power to keep the lights on for its customers in Los Angeles and San Diego.
Cost recovery options?
It is not clear whether SCE will be able to recover some or any of these costs from its customers. Also, SCE will be looking at its contract with MHI to determine how to recover repair costs. The 'all-in" cost of installing the steam generators in 2010 was $670 million, but the contract provides a warranty less than one quarter of that amount or $137 million. The fact that MHI erred in its calculations used in the design of the steam generators will likely push the issue of liability into the realm of legal experts, litigation, or mediation/arbitration.
SCE has insurance through the Nuclear Electric Insurance Ltd (NEIL)organization, which is also facing the potential for massive claims from the Progress Energy Crystal River reactor that has a damaged containment structure. It has been out of service since 2009.
Both SONGS reactors began operations in 1982 and their NRC licenses come up for a 20-year extension in 2022. The fact that both reactors have plenty of life left in them, from a regulatory perspective, means that SCE has an incentive to pursue a path to get them to operate again at full power. This option could include replacing the steam generators rather than repairing them. The latter option carries the penalty of lost income from operating at less than full power for a a decade or longer.
Cost estimates increase for repairs at Crystal River
|Damage to the containment structure|
at Crystal River
The information was provided by Duke Energy CEO Jim Rogers in an interview. Rogers told the newspaper that no decision has been made whether to repair or retire the reactors. The containment structure was severely damaged during a steam generator replacement project.
The Nuclear Electric Insurance Ltd has stopped payments for the repairs and replacement power and is conducting its own review of the situation.
According to the Tampa Bay Times, Lynn Good, Duke Energy's CFO, said that the cost estimates for repairs were developed in 2011. She said engineers are now revisiting that analysis, but declined to offer a new figure.
Rogers told the newspaper that the cost estimates he's seen so far are higher than the 2011 numbers. He said that while repairs are "technically feasible, issues remain that will affect the decision to repair or close the plant."
Those issues are more likely on the financial side. Unlike all of Duke's other reactors in the combined firm, Crystal River is still operating under its original license which expires in 2016. The NRC is unlikely to renew the license of a reactor with a breached containment structure if Duke cannot complete the repairs in time.
Duke Energy merged with Progress in July. Financial numbers for the combined firm will be reported for the first time in 3Q2012. The lack of revenue from the Crystal River plant contributed to a steep drop in earnings reported by Progress from $176 million in 2Q2011 to $63 million for the same period in 2012.
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