SCANA Delays New Reactor Startup, Accelerates Coal Plant Retirements

South Carolina Electric & Gas (SCE&G) last week announced that startup of the $6.3 billion nuclear extension under construction at its V.C. Summer plant could be delayed by up to a year owing to delivery issues. The SCANA Corp. subsidiary, which last year identified six coal-fired units that would be retired or switched to natural gas to comply with looming Mercury and Air Toxics Standards (MATS), also said it plans to accelerate retirement of two units by the end of this year.

SCE&G in March completed placement of basemat structural concrete for two new AP1000 reactors at its V.C. Summer Unit 2 in Fairfield, S.C. SCANA Corp. CEO Kevin Marsh told analysts during a June 5 meeting that the company had since placed a CR-10 module and a containment vessel bottom head in the Unit 2 nuclear island.

The project is, however experiencing delivery delays of its 70-foot-tall CA-20 module from Chicago Bridge & Iron (CB&I), which acquired Shaw Co. this February. The module, which is a large portion of the auxiliary building, including the spent fuel pool, was to be delivered in 72 different submodules fabricated by a CB&I Lake Charles, La., facility. But delivery was problematic, as executives at SCANA explained: "Some of it is normal startup-type things, because it is a new facility," including documentation and quality issues, they said.

The company said an updated schedule from CB&I suggested in-service dates for Unit 2 would need to move from the currently approved March 2017 date to one in the fourth quarter of 2017 or the first quarter of 2018. State regulators allow SCANA Corp. to accelerate its 146 outlined milestones by 24 months or delay them by up to 18 months.

"Oftentimes, we hear about nuclear projects being over budget or costs being rampant. And I want to reinforce that, that is not the case with this project," said Senior Vice President Stephen Byrne. The $6.3 billion price tag approved by South Carolina regulators in early 2009 included capital costs, the owner’s cost, escalation, and Allowance for Funds Used During Construction (AFUDC). SCG&E’s own more recent projections showed the project was at $5.8 billion, due to "very favorable conditions or terms and conditions we’ve been able to get out from the financings and then escalation coming in much lower than we had anticipated," Byrne said.

Regarding its coal capacity, the six coal units that the Cayce-based utility last year identified for potential shutdown or fuel switching—its oldest and smallest units—are worth a total of 730 MW. Three units are part of the company’s Canadys Station.

Byrne told analysts at the June 5 meeting that SCE&G retired one of the six units at the end of 2012 and converted another one to natural gas from coal. SCE&G had planned to convert the remaining two to natural gas–fired units as an interim measure before retiring them completely in 2017. However, after reevaluating system needs and analyzing the economics of the situation, the company last week decided to proceed with retiring the plant by the end of this year.

For the four remaining units, the company evaluated MATS compliance extensions beyond the April 2015 deadline. "The first year waiver, you can get from an authority. So in our case, that would be the [South Carolina] Department of Health and Environmental Control. … So we did seek the first year extension for 4 of those fossil units, for those smaller coal units, and received that [one] year extension," he said.

But justification for the second-year waiver from the U.S. Environmental Protection Agency (EPA) was harder. When the company surveyed if it could purchase power from the market, "we got more responses than we had anticipated and the pricing came back more favorably than we anticipated. So the power was available, the power was out there. So that meant that the second-year extension was not likely from the [EPA] ," Byrne said. A further determination showed that it would be cheaper to purchase power than continue operating the roughly 50-year-old coal units. "So the business case said that we should retire those units businesses early."

The company’s plans would help it meet increasingly stringent environmental regulations and achieve a more balanced generation portfolio. “By the end of 2018, we anticipate that roughly one-third of our electric generation will be fueled by nuclear power, one-third by natural gas, and one-third by scrubbed coal-fired plants,” said Byrne.

Figures released in January 2013 by consulting firm The Brattle Group show that about 32 GW of coal capacity retirements will be retired by 2021 as compliance deadlines with EPA rules for existing coal-fired power plants approach—including MATS and regional haze rules.

About 80% of these, or 24 GW, will have been shuttered by 2015 because most lack major environmental controls. This year, as much as 3.5 GW will be retired, but in 2014, at least 6.7 GW is scheduled to be retired. Most projected and announced coal retirements are in the Southeast. The group also projects that a 6 billion cubic feet/day gas demand increase could spur the retirement of 60 GW of coal capacity by 2016 nationwide.

Sources: POWERnews, SCE&G, The Brattle Group

—Sonal Patel, Senior Writer (@POWERmagazine, @sonalcpatel)