US power generator and distributor, Entergy, will have three boiling water reactor power plants undergoing a decommissioning process within the next four years. NEI considers what the impact will be and tracks the developments that led to the decision.
By 2020, Entergy will have three nuclear power plants being decommissioned. All of them are single-unit merchant plants with boiling water reactors (BWRs) and all are in the Northeastern US.
The shutdowns will reduce the number of power reactors New Orleans-based Entergy operates by a third. Entergy owns and operates ten reactors, including six merchant, across several US states and provides support and management services for an 11th reactor, Nebraska Public Power District’s Cooper plant in Brownville, Nebraska. The shutdowns also will reduce Entergy’s owned and operated nuclear sites from nine to six.
Entergy shut down Vermont Yankee (one unit, 604MWe) in Vernon, on 29th December 2014. In 2015 the company announced it would shut down two additional BWRs over the next three years: the Fitzpatrick (838MWe) in New York would close in late 2016 or early 2017 and Pilgrim (688MWe) in Massachusetts in 2019. In all three cases, Entergy said it was closing the plants for economic reasons, citing ‘wholesale market flaws’ that made it uneconomic to operate the plants.
All three plants had already received Nuclear Regulatory Commission (NRC) license amendments that would have allowed them to operate for an additional 20 years beyond their initial 40-year operating period. Fitzpatrick received its license extension in September 2008, Vermont Yankee in June 2011, and Pilgrim in May 2012.
At the time it shut down, Vermont Yankee had operated for 42 years and received a 20-year renewal of its NRC license that would have allowed it to operate until 2032.
Since 2002 Entergy has invested more than $400 million in upgrading Vermont Yankee to meet the conditions for an extended license. At the time it closed the plant Entergy said: ‘The financial impact of cumulative regulation is especially challenging to a small plant in these market conditions.’ It blamed low natural gas prices and ‘wholesale market design flaws’ that result in artificially low energy and capacity prices in New England. These market flaws do not allow adequate compensation to merchant nuclear plants for the fuel diversity benefits they provide, according to a company statement.
The closure could affect power supply reliability in Vermont and New England for years to come. US nuclear trade association Nuclear Energy Institute said Vermont Yankee generated 72% of Vermont’s electricity and that made Vermont the US state with the highest portion of its electricity generated by nuclear power. With 22% of the state’s power generated by hydropower, Vermont ranked lowest in the nation for carbon emissions from electricity production. The nuclear plant also allowed Entergy to export electricity to Connecticut, Maine, Massachusetts, New Hampshire and Rhode Island.
At the time of the Vermont Yankee shutdown, Entergy was examining all six of its merchant plants with an eye to closing those where profits lagged.
In October 2015 it announced plans to close the Pilgrim plant by mid-2019. Pilgrim is the only operating nuclear unit in Massachusetts. Entergy said operation was not economically viable, citing increased operating costs and reduced revenue. Pilgrim’s economic performance also suffered from ‘unfavourable state energy proposals that subsidies renewable energy resources at the expense of Pilgrim and other plants’, an Entergy statement read.
Entergy said it notified grid operator ISO- NE that Pilgrim would not participate as a capacity resource in the market after 31st May 2019, but the exact timing of the closure was unclear and it plans to make a final decision on timing by mid 2016. Pilgrim may close as early as the end of its current operating cycle in 2017 depending on the increased cost of regulatory recovery, any additional regulatory challenges and the availability of economically viable replacement capacity.
Entergy CEO Leo Denault told stockholders on 18th February, while reporting 2015 fourth quarter results, that Entergy would decide in June 2016 whether to refuel Pilgrim one more time in 2017 for an additional two-year fuel cycle.
Decommissioning will begin as soon as Pilgrim shuts down. Entergy said that, at the end of September 2015, Pilgrim had $870 million in its decommissioning fund, about $240 million more than NRC requires for its license termination.
The company announced the closure of FitzPatrick, by late 2016 or early 2017, in November 2015. Again it cited increased operating costs, reduced plant revenues and poor market design as well as sustained low wholesale energy prices, driven down by record low gas prices due to the plant’s location close to the Marcellus shale formation. Entergy said low energy prices would reduce its revenues by $60 million per year.
Entergy said it would close the plant at the end of its current fuel cycle. The 40-year-old plant had renewed its license with NRC approval to operate until 2034.
The New York system operator found that the loss of FitzPatrick, combined with the closure of several other facilities, would result in a shortfall in 2019. Denault said: "There will be more cost effective solutions to fill this need". The Pilgrim retirement in June 2019 would not present any reliability issues.
After the shutdowns Entergy will have three merchant PWRs Indian Point 2 (1028MWe) and 3 (1041MWe) in New York, and Palisades (811MWe) in Michigan. After announcing the FitzPatrick shutdown Denault said Entergy remained committed to nuclear power, but that "we have been assessing each asset".
Nuclear Energy Institute President and CEO Marvin Fertel said FitzPatrick would be the fourth nuclear plant to close prematurely due what he called "flaws in competitive electricity markets". Fertel added: "It is clear that, despite providing reliable electricity and enormous environmental and economic benefits in upstate New York for more than 40 years, FitzPatrick’s benefits are grossly undervalued." Fertel added the nuclear industry "has been engaging with regulators and other leaders to communicate the wholesale market reforms that are needed".
Moving into decommissioning
Vermont Yankee will be the model for decommissioning Entergy’s BWRs; the company is moving fast. In December 2015 it announced it would start transferring spent fuel from the plant’s storage pool – where the final assemblies were transferred in January 2015 – to dry storage in 2017, two years earlier than originally planned. The accelerated start aims to ensure all fuel is transferred from the pool to dry storage by 2020.
By 2017 Entergy plans to complete a second onsite Independent Spent Fuel Storage Installation (ISFSI). To meet that schedule Vermont Public Service Board must approve the start of construction in early 2016.
In July 2015, Entergy selected Holtec’s HI- STORM 100 dry storage system, comprising stainless steel multi-purpose canisters with a welded base plate and lid, each of which can hold up to 68 fuel assemblies. The canister is placed inside a carbon steel and concrete overpack, then placed on the concrete storage pad. Supplier Holtec can meet Entergy’s accelerated schedule Entergy said.
The overall cost of the dry storage project will remain $145 million, including construction of the second storage pad, but some costs will be incurred earlier than planned with the accelerated schedule the company said. The cost includes procurement and fuel transfer. Money for the dry storage project will come from extended credit line, rather than Vermont Yankee’s Nuclear Decommissioning Trust Fund.
On 10th December 2015, NRC approved changes to Vermont Yankee’s emergency planning requirements to reflect the plant’s decommissioning status. Since April 2016, Entergy has no longer had to maintain a 10- mile emergency planning zone, as required by its operating license. The change reflects the lower risk of offsite radiological releases and the fewer types of possible accident at a shut down plant that has been defueled. Vermont Yankee will maintain an on-site emergency plan and emergency capabilities.
Overall, Vermont Yankee estimates the decommissioning will cost more than $1.2 billion and take until 2075. The company has opted for the SAFSTOR option, which delays final plant dismantling to allow for radioactive decay. The Vermont Yankee Decommissioning Trust Fund currently contains about $600 million; Entergy is relying on interest accumulation over the SAFSTOR period May 2016
to cover the full decommissioning cost. In part, the schedule for final plant dismantling depends on the growth of the trust fund.
According to a regular video update by Joe Lynch, manager of governmental affairs at Entergy, much of 2015 was spent draining the reactors piping systems and laying up other systems. Of the 50 systems that were targeted, about 35 were shut down in 2015. "The effort focused on removing all fluids from the systems," Lynch said. Power and heat has been removed from some auxiliary buildings to save energy, since now Vermont Yankee must buy all its electricity. In 2015, Vermont Yankee was paying more than $100,000 a month in electric bills to Green Mountain Power, Lynch said.
In October 2015, the plant and its operators performed the last emergency drill, which was needed to keep employees up-to-date and in qualified positions. In November 2015, one of the last siren tests of the emergency management zone was carried out. At that time, Lynch said Vermont Yankee was in discussions with nearby towns over whether the sirens would be removed or maintained by the towns for long-term use.
The Post Shut Down Decommissioning Plan took effect in April 2016, at which time the 10-mile emergency planning zone should have been scaled back to the plant boundary.
The plant cut staff from 550 at the time of shutdown to 316 in January 2015, making 234 redundant. In January 2016 staff numbers dropped to 282. In May 2016 staff will be cut again to between 150-175 employees. Entergy has said it will try to place employees elsewhere in the company but the impending shutdown of Pilgrim and FitzPatrick are reducing the options. The company is also conducting a series of workshops and seminars on outside employment, financial planning and selling homes in a tight real estate market.
At this stage NRC continues to perform regular inspections and provide quarterly inspection reports, Lynch said.
Currently, Entergy must list withdrawals from the Decommissioning Trust Fund as well as whether they include taxes, legal fees, or emergency planning funds for NRC with 30-days notice and provide advance notice of withdrawals to the state of Vermont. Lynch said Entergy had requested a license amendment from NRC that would exempt it that requirement.
The company has received NRC approval to use the Decommissioning Trust Fund for items other than physical or radiological decommissioning, but Vermont, Green Mountain Power, and the former Vermont Yankee Corporation have filed a lawsuit against NRC in the Washington DC District Court. Lynch said Entergy expected a favourable result at the conclusion of the suit.
As of 31st December 2015 the Trust Fund stood at $595.443 million. An earlier $69.1 million withdrawal was used for physical decommissioning, market losses and gain as well as trust fees such as administrative fees and taxes imposed by the trustee for maintaining the fund. "The good news is that we are under budget for the project", Lynch said, adding the trust looked "healthy" at that point.
He also provided an update on interactions with the Vermont Public Service Board (VPSB) and the Vermont Agency of Natural Resources (VANR).
VANR completed an inspection for the site’s hazardous waste management and noted a number of findings and observations. They informed plant managers of alleged violations, including poor labelling of waste paint, a sign that could not be read from a certain distance, and need for a more "rugged" barrel for some wastes on the site. Lynch said these violations had, however, since been corrected.
The 19-member Nuclear Decommissioning Citizens Advisory Panel, formed by the state legislature, met for the first time in September 2014, and monthly thereafter until December 2014. It met 12 times in 2015 – up form the original plan for quarterly meetings.