The World Nuclear Industry Status Report 2019 (HTML)

With 97 commercial reactors operating as of 1 July 2019, the U.S. possesses the largest nuclear fleet in the world. Construction has continued on the one new nuclear plant in the U.S., the twin AP-1000 at Plant Vogtle-3 and -4, following a vote of the owners in September 2018 to continue the project.382 Further cost increases have been reported but with reportedly an improved work schedule.

Two reactors, both General Electric BWR MK 1 designs, were permanently closed in the year to 1 July 2019. The Oyster Creek-1 reactor in New Jersey generated its last kilowatthour on 17 September 2018.383 Connected to the grid in September 1969, it was the oldest operating commercial reactor in the U.S., and was required to be closed no later than December 2018 under an agreement with the state.384 On 31 May 2019, Entergy permanently shut down its Pilgrim reactor in Massachusetts, which was connected to the grid on 19 July 1972.

The fallout from the decision in July 2017385 to terminate construction of the twin V.C. Summer AP-1000 reactors continued through the past year. This included legal action over the recovery of billions of dollars of ratepayers’ money lost to the abandoned project,386 ongoing disclosures of the failure of the project and culpability of utility executives,387 including criminal investigations, and the takeover of the V.C. Summer owner, South Carolina Electric & Gas (SCG&E) and its parent SCANA, by Dominion.388

During the past year, utilities have both succeeded and failed in their ongoing efforts to secure state financial support for operating nuclear plants, with the balance being in the industry’s favor. As of 2019, subsidies will be provided to eight nuclear plants in the U.S., in the form of Zero Emission Credits (ZEC): Nine Mile Point, FitzPatrick and Ginna in New York; Clinton and Quad Cities in Illinois; Salem and Hope Creek in New Jersey; and Palisades in Michigan.389 Legal challenges against ZEC nuclear legislation from consumers, NGOs and energy companies are ongoing in all of these states.

The Nuclear Energy Institute (NEI), the advocacy organization for the U.S. nuclear industry, has continued to lobby for financial support for nuclear plants,390 while the Department of Energy (DOE) provided a further loan guarantee of US$3.7 billion to Plant Vogtle construction, the first and only loan guarantee issued under the Trump administration so far.391 This brings the total loan guarantees provided by the DOE for nuclear new-build projects to US$12.03 billion.392

In a further measure to reduce costs for reactor operators, the Nuclear Regulatory Commission’s (NRC) commissioners on 24 January 2019 voted by majority to remove safety requirements proposed in a draft rule making issued in 2016, that, if applied, would have forced utilities to take measures to upgrade their plants to protect against such hazards as flooding and major seismic events.393 The draft NRC rulemaking had already rejected stricter measures proposed by the “Near Term Taskforce Review of Insights from the Fukushima Daiichi Accident” in 2011.394

While it is inevitable that the size of the U.S. nuclear fleet will continue to decline for the foreseeable future, the decline is likely to be slowed by directly subsidizing economically threatened operating plants.

The U.S. reactor fleet provided 808.03 TWh in 2018—a new historic maximum—compared with 805 TWh in 2017. Consequently, the load factor remained stable at a high level (89.8 percent), significantly above the modest lifetime load factor of 75.9 percent. Nuclear plants provided 19.3 percent of U.S. electricity in 2018, compared with 20.1 percent of U.S. electricity in 2017, and about 3 percentage points below the highest nuclear share of 22.5 percent, reached in 1995.

With only one new reactor started up in 20 years, the U.S. reactor fleet continues to age, with a mid-2019 average of 38.9 years, amongst the oldest in the world: 46 units have operated for 41 years or more.

Sources: WNISR, with IAEA-PRIS, 2019

In the year to 1 July 2019, NRC issued 20-year license renewals for four nuclear plants (five reactors): Indian Point-2 and -3395, River Bend-1396, Waterford-3397, and Seabrook-1398. Utility owners of two nuclear plants submitted applications for subsequent license renewal, which, if granted, could see the reactors operate for an additional 20 years beyond their current sixty-year license. Exelon Generation Company, LLC (Exelon), applied to the NRC on 10 July 2018 for subsequent license renewal for Peach Bottom-2 and -3.399 These reactors, both connected to the grid in 1974, are General Electric MK1 BWRs.

The subsequent license request for Peach Bottom -2 and -3 is being contested by the organization Beyond Nuclear.400 In evidence seeking a review by the Atomic Safety Licensing Board (ASLB), expert witness Dave Lochbaum contends that Exelon in its application to the NRC had failed to address how operating experience will be applied during the 60–80-year period of operation of Peach Bottom-2 and -3. This is despite the fact that “[a]bundant evidence also speaks to gaps, deficiencies, and uncertainties in present understanding of aging degradation mechanisms.” 401

In October 2018, Dominion Energy Virginia submitted its Subsequent License Renewal application for the Surry Power Station 1 and 2, which were connected to the grid in March 1972 and March 1973 respectively.402 The NRC is now reviewing six reactors for 60–80-year operation, following the application for the Turkey Point-3 and -4 reactors in May 2018.403 The NRC is planning to issue a final decision on the Turkey Point reactors in October 2019.404 In July 2017, the NRC published a final document describing “aging management programs” that might allow the NRC to grant nuclear power plants operating licenses for “up to 80 years”.405

As of 1 July 2019, 89 of the 97 operating U.S. units had received a license extension.406 However, experience shows that many reactors are closing long before their license expires.

Reactor Closures

On 17 September 2018, the oldest reactor in the U.S. fleet, the 650 MW Oyster Creek reactor in New Jersey, entered permanent closure. Exelon, the owner of the 49-year-old BWR GE MK1 connected to the grid on 23 September 1969, had confirmed its intention for closure in February 2018.407 The safety of the reactor had long been under contention from a coalition of NGOs, including evidence of severe corrosion of the reactor containment system that was effectively ignored by the NRC during the reactor’s relicensing process in the mid-2000s.408 The NRC issued 20-year life extension approval for Oyster Creek in August 2009, granting the reactor operation until 2029.

In August 2015, Exelon had announced that Oyster Creek (together with Quad Cities and Three Mile Island) had not cleared the Pennsylvania New Jersey Maryland Interconnection LLC (PJM) capacity auction for the 2018–19 planning year.409 Exelon announced on 31 July 2018 that Holtec International was interested in the purchase of the Oyster Creek reactor.410 The NRC approved the sale to Holtec on 20 June 2019.411 As WNISR 2018 reported, this model of transferring ownership was already adopted by the utility Entergy for its Zion plant in Illinois (with ownership transferred to EnergySolutions). These developments are problematic as limited-liability companies are only financially liable—in the case of an accident or other legal dispute—up to the value of their assets. Therefore, if the decommissioning funds are exhausted, such a third-party company could declare bankruptcy, leaving the bill for the taxpayer.412

On 31 May 2019, Entergy permanently closed its 47-year old GE MK1 Pilgrim reactor. The 668 MW unit was connected to the grid on 19 July 1972.413 Senator Ed Markey described the plant as having “one of the worst safety records of any nuclear facility in the country”.414 The reactor remained embroiled in safety concerns, not least after four emergency shutdowns (SCRAMs) between 2013–15.415 Long-standing opponents of the plant had challenged Entergy’s application for a 20-year license extension, which was granted by the NRC in 2012, though opposed by then NRC Chair Gregory Jazcko, and which permitted the reactor to operate until 2032.416 Only three years after being granted lifetime extension, Entergy was facing mounting costs, including for safety retrofits, which the utility was reluctant to invest in. These difficulties, combined with loss of competitiveness in the electricity market, led Entergy in 2015 to announce that Pilgrim was “simply no longer financially viable” and would be closed on 31 May 2019.417

In November 2018, Entergy filed notice with the NRC for the sale of the Pilgrim reactor to Holtec International. Holtec would take ownership after closure, justified by the utility on the grounds that Holtec would “complete decommissioning and site restoration decades sooner than if Entergy completed decommissioning”.418

Exelon Generation announced on 8 May 2019 that Three Mile Island-1 (TMI) will permanently close by 30 September 2019.419 The 45year old reactor was connected to the grid on 19 June 1974. In 2009, the NRC granted a 20-year license extension to operate until 2034. In August 2015, TMI did not clear the PJM capacity auction for the 2018–19 planning year,420 and Exelon warned in 2017 that failure to approve subsidies by the Pennsylvania legislature before 1 June 2019 would lead to the reactor’s closure.421 As of 1 July 2019, no such legislation had been passed (see section on Zero Emission Credits (ZECs) hereunder). The decision to finally close nuclear operations at the power plant site came 40 years after TMI-2 suffered a partial core fuel meltdown on 28 March 1979. (See Table 8 and Figure 33).

Sources: Various, compiled by WNISR, 2019

Sources: Various, compiled by WNISR, 2019

Notes

a - Early closure potentially reversed – see Table 9.

b – According to the NRC, FENOC indicated that with the planned closure of Perry they no longer plan to submit a license renewal application422.

SCE: Southern California Edison; SDG&E: San Diego Gas & Electric; PG&E: Pacific Gas & Electric Company; OPPD: Omaha Public Power District

New Reactor Construction

“If we were deciding today, I don’t think we would decide to build these units (at Plant Vogtle) because natural gas and solar are so cheap today.”
Tim Echols, Georgia Public Service Commission (PSC) who voted for completing the Vogtle project in May 2019.423

The cancellation of the V.C. Summer reactors means that the only new nuclear plant construction in the United States is Plant Vogtle in Georgia. Construction of Vogtle-3 officially began in March 2013, with Unit 4 following in November 2013.424 The original project cost approved by the Georgia Public Service Commission (PSC) was US$6.1 billion in 2009, which corresponds to a cost of US$2,350/kW, whereas the 2017 cost estimates of US$23 billion translates to a cost of US$10,000/kW. The revised 2018 estimates in the range of US$28 billion have increased costs to US$11,000/kW.425 These costs compare with the Massachusetts Institute of Technology (MIT) 2009 assessment of the prospects for new nuclear power based on overnight costs of US$20074,000/kW426 (US$20184,800). During the past year, further cost increases have been reported. There are differing opinions on completion schedules with the utility expressing confidence that it can meet target dates of November 2021 and November 2022 for Units 3 and 4 respectively. Critics of the Vogtle project had long predicted over the past decade that costs would be much higher, as now confirmed.427

As WNISR2018 reported, on 31 August 2017 Southern Company (parent company of majority Vogtle plant owner, Georgia Power) filed its recommendation with the Georgia PSC to continue construction of Vogtle—supported by its other owners Oglethorpe Power Corporation (OPC), Municipal Electric Authority of Georgia (MEAG) and Dalton Utilities.428 In addition to continuation of the project, Georgia Power reported that it had also reviewed the options of cancellation of Unit 4, as well as cancellation of both units. The recommendation was based on the results of a comprehensive schedule, cost-to-complete and cancellation assessment, according to Southern Company. The President of Georgia Power stated that “Completing the Vogtle-3 & 4 expansion will enable us to continue delivering clean, safe, affordable and reliable energy to millions of Georgians, both today and in the future”.429

As WNISR2018 also reported, in December 2017 the Georgia PSC, following the recommendation from Southern Company, decided to continue to support the project. The Georgia PSC has backed the Plant Vogtle project from the start, including awarding the generous Construction Work In Progress (CWIP), where all construction costs incurred by Georgia Power are passed directly on to the customer. The Georgia Nuclear Energy Financing Act, signed into law in 2009, allows regulated utilities to recover from their customers the financing costs associated with the construction of nuclear generation projects—years before those projects are scheduled to begin producing benefits for ratepayers. As a result of the CWIP legislation, out of Georgia Power’s original estimated US$6.1 billion Vogtle costs, US$1.7 billion is financing costs recoverable from the ratepayer. The utility began recovering these financing costs from its customers starting in 2011. For that first year, the rule translates to Georgia Power electric bills’ rising by an average of US$3.73 per month. Georgia Power estimated that this monthly charge would escalate so that by 2018, a Georgia Power residential customer using 1,000 kWh per month would have seen his/her bill go up by US$10 per month due to Vogtle-3 and -4. As a result of increased costs of the project and approval by the PSC, ratepayers had already paid US$2 billion to Georgia Power as of November 2017.430 But given the long timescale of the project, including planned operational life, the actual costs to ratepayers will be much higher. In December 2017, under cross-examination from Georgia Watch, a public interest group, Georgia PSC staff had confirmed that “the nominal life cycle capital cost revenue requirement collected from ratepayers would increase from US$23 billion to US$37 billion...” Georgia Watch’s Liz Coyle concluded that “if the Commission adopts the Company’s recommendations as filed, the Company profits will increase by 5.2 billion dollars and ratepayers will pay an additional 14 billion dollars.”431

In early August 2018, Southern Company reported that it had revised its own expenditure for the project from US$7.3 billion to US$8.4 billion, stating that the increase would be absorbed by the company (i.e. its shareholders), not by customers.432

As to the construction schedule, in 2017, officially Southern Company gave fuel-loading times as November 2021 for Unit 3 and November 2022 for Unit 4, which compares with an original planned startup date of 2016. However, the operational dates from Southern are at variance with the assessment made by the Georgia PSC in its December 2016 quarterly progress report, which indicated a credible completion date of 2023. Obtained by E&E News433—one public version, the other classified as “Highly Confidential Trade Secret EPC Information”—the report cast major doubts on the company’s estimated completion dates of the Vogtle reactors, with future long-term activities identified by “staff as high risk for delay.” Although both versions of the report were heavily redacted, it confirmed that “there have been continued delays” and “that all of the paths to Unit 3 completion are under schedule stress and will likely incur additional delays.”434 The 2023 date itself was highly speculative, and was on the basis of maintaining the 2016 nine-percent annual construction completion-rate, with no further delays, which given the track record of the project must be in serious doubt.

During the past year, Southern Company reported that the completion schedule was on track. On 20 February 2019, Southern Company’s CEO Tom Fanning said that “a lot of work ahead of us to sustain this performance, but we are pleased with our progress and are confident that we can meet the schedule approved by regulators.”435 The optimism of the utility contrasts with continuing warnings from Georgia PSC staff. In their November 2018 report to the Georgia PSC, which was an analysis of the “Nineteenth Semi-Annual Vogtle Construction Monitoring Report”, they questioned both the credibility of the construction schedule and the risk of further cost increases, noting that “the +21-month schedule is highly unlikely to be achieved” and even the “+29-month schedule is also stressed.”436 In terms of costs, the Georgia PSC staff noted that at “the monthly spending rate, currently $200 million per month (100 %) on the Project, the cost consequences of Project delay could be severe depending on the duration of the delay.” Staff concluded that “at this time the status of the Project is uncertain,”437 with major uncertainties whether the target date of Hot Functional Tests scheduled for Unit 3 on 31 March 2020 can be achieved. Fuel loading is scheduled for 14 October 2020.

According to a media write-up,438 during December 2018 hearings on the latest assessment from Southern, expert testimony warned that the cost to ratepayers will be nearly “US$4 billion in financing costs and income tax expenses upon completion. That figure is likely to increase and affect ratepayers who have financed the project since construction began in 2011”; with experts warning that “a delay of more than eight months may deem the project, now about 71 percent complete, ‘uneconomic to continue.’”439

At the February 2019 session of the Georgia PSC, regulators approved a further US$526.4 million in costs for the Vogtle plant to be paid for by Georgia ratepayers.440

As reported in WNISR2018, on 13 February 2018 a coalition of groups filed in Fulton County Superior Court a complaint challenging the Georgia PSC decision, declaring that it was unlawful, violating the PSC’s own guidelines and Georgia state law.441 The coalition contended that new investments in solar power and energy efficiency would be less risky, more affordable, and more than up to the job of powering Georgia’s economy. On 21 December 2018, the court found that dissatisfied customers cannot raise concerns about the unfairness of Goergia PSC process “until 2022 or later, after the project is complete.”442 “The court dismissed the appeal on technical grounds without addressing its substance,” attorney Kurt Ebersbach of Southern Environmental Law Center (SELC) stated.443 “The people of Georgia have been pre-paying for this mismanaged project since 2011, while the price tag has ballooned and the project timeline has slipped again and again,” Liz Coyle, executive director of Georgia Watch, said. “Unless the court reverses the commission’s decision, Georgia Power customers remain exposed to significant financial risk with seemingly no end in sight.”444 The groups are planning to challenge the court decision.

Under the financing terms agreed with the Georgia PSC, the longer the Vogtle plant takes to construct, the higher its costs, which have invariably been passed on to Georgia ratepayers, resulting in higher income streams for Georgia Power and therefore Southern. In reporting 2018 Southern earnings, CEO Thomas A. Fanning stated that, “2018 was a banner year for Southern Company (...) All of our state-regulated electric and gas companies delivered strong performance.” Full-year 2018 earnings were US$2.23 billion, compared with earnings of US$842 million in 2017.445

The Vogtle plant construction has faced ongoing legal challenges since approval for construction in 2009. On 19 February 2019, the Fulton County Superior Court in Georgia granted class-action status to a lawsuit challenging charges Georgia Power Co. collects from customers each month related to Vogtle construction. The lawsuit, originally filed in 2011,446 charges Georgia Power with artificially raising municipal franchisee fees. “This is a good day for electric power customers in Georgia. For the first time in over seven years, a court has authorized plaintiffs to move forward as a group representing all two million-plus ratepayers”, said the plaintiffs’ lawyer and former speaker of the state House of Representatives, Glenn Richardson.447

In a separate lawsuit, on 18 June 2019, the Georgia Court of Appeals heard arguments about whether the 2017 Georgia PSC decision to continue the construction of Vogtle broke regulatory rules.448 The coalition of citizens’ organizations challenging the Georgia PSC, including Georgia Watch and Georgia Interfaith Power and Light, filed the appeal after their case was dismissed on technical grounds in December 2018.449 They contend that the 2017 decision approving the completion of the Vogtle reactors should have been subject to judicial review.450 Under Georgia PSC guidelines, commissioners are not required to judge whether costs are prudent until after the plant is complete, when retroactive prudency hearings are held. Only then advocates are allowed to challenge expenses. As the lawyer representing the plaintiffs states, “And that’s their [Georgia Power’s] argument: ‘Wait until we build it.’ But if you wait ‘til you build it, you can’t go back and say, was it right to continue? It’s moot at that point. They’re taking away one of the powerful arguments to hold the company accountable, which is whether or not the additional expenses are reasonable. And that matters. Because it shifts the burden of proof.”451 Georgia Power’s attorney stated that “It’s not a question of whether they can seek judicial review. It’s a question of when.”452 A decision by the court is expected by the end of 2019.

Vogtle Federal Loan Guarantees

Under the terms of the Department of Energy (DOE) Loan Guarantee Program, owners of nuclear projects are able to borrow at below-market Federal Financing Bank rates with the repayment assurance of the U.S. Government. DOE loan guarantees permitted Vogtle’s owners to finance a substantial portion of their construction costs at interest rates well below market rates, and to increase their debt fraction, which significantly reduced overall financing costs. In justification for the loan guarantee to Vogtle, the Obama administration stated in 2010 that

the Vogtle project represents an important advance in nuclear technology, other innovative nuclear projects may be unable to obtain full commercial financing due to the perceived risks associated with technology that has never been deployed at commercial scale in the U.S. The loan guarantees from this draft solicitation would support advanced nuclear energy technologies that will catalyze the deployment of future projects that replicate or extend a technological innovation.453

The loan guarantee program has therefore played a critical role in permitting the Vogtle project to proceed but has failed to catalyze a nuclear revival, with no prospects of further new nuclear plants being built in the U.S. in the coming decades. Oglethorpe Power Corporation (OPC), which has a 30 percent stake in Vogtle, confirmed in August 2017 that it had submitted a request to DOE for up to US$1.6 billion in additional loan guarantees. The company already had a US$3 billion loan guarantee from DOE. The other owners, Georgia Power and Municipal Electric Authority of Georgia (MEAG), have secured US$8.3 billion in separate loan guarantees from DOE since 2010, when they were approved by the Obama administration. Both of these companies confirmed in August 2017 that they were seeking additional loan guarantee funding.

On 29 September 2017, DOE Secretary Perry announced approval of additional US$3.7 billion loan guarantees for the Vogtle owners, with US$1.67 billion to Georgia Power, US$1.6 billion to OPC, and US$415 million to MEAG.454 A decision on terminating the Vogtle project would raise the prospect of repayment of the previous US$8.3 billion loan to Southern.455

In April 2019, the DOE provided a further loan guarantee of US$3.7 billion to Plant Vogtle construction, only the second loan guarantee issued under the Trump administration and the second to Plant Vogtle.456 This brings the total loan guarantees provided for the Vogtle project by the DOE to US$12.03 billion.457

Ongoing Fallout from Termination of V.C. Summer Project

As in WNISR2018, the decision on 31 July 2017 by Santee Cooper and SCANA Corporation (the parent company of South Carolina Electric & Gas or SCG&E) to terminate construction of the V. C. Summer project during the past year has seen ongoing financial and legal fallout for the companies and ratepayers of South Carolina.

On 24 November 2018, SCANA and SCG&E agreed to a US$2 billion settlement to resolve a ratepayer lawsuit over cost recovery for the abandoned V.C. Summer nuclear expansion project.458 Under the controversial Base Load Review Act (where ratepayers pay during the construction period) there had been nine rate increases that to date have cost ratepayers US$2 billion. Under the agreement, approved by the Georgia PSC on 14 December 2018, while there was to be a reduction of 15 percent in electricity prices, South Carolina’s citizens will continue to pay towards the abandoned project for an additional US$2.26 billion over the next 20 years.459 The decision of Georgia PSC was part of an overall settlement whereby SCANA would be taken over by Dominion Energy; the utility had threatened to walk away from its SCANA takeover if the Georgia PSC were to approve higher rate cuts.460 Critics of the agreement estimated that total costs to ratepayers will amount to US$5 billion.461 When V.C. Summer was cancelled in 2017 total costs for completion of the two AP-1000 reactors was projected to exceed US$25 billion—a 75 percent increase over initial estimates.462

Meanwhile, legal action against SCANA continues in 2019, including a civil fraud lawsuit that will proceed to jury trial,463 with a ratepayers’ lawyer telling the federal court judge: “The bottom line is they (SCANA executives) lied to everyone, and they did it intentionally.”464 It is known that since 2017 the Federal Bureau of Investigations (FBI) and the U.S. Attorney’s office of South Carolina have been conducting an investigation into alleged criminal fraud by former SCANA top officials.465

The cancellation of the V.C. Summer project adds to the history of 40 other stranded nuclear reactor projects in the United States whose construction started in the 1970s and which were abandoned between 1977 and 1989, as can be seen from the WNISR’s Global Nuclear Power Database.466

Securing Subsidies to Prevent Closures

“This is the only industry known where when you’re not doing well you don’t go to shareholders and have them pay and suffer the losses, you go to the ratepayers and make them pay. This is a bailout for aging and obsolete technology.”
Ohio State Senator Sean O’Brien, May 2019 467

Utilities have been actively lobbying for state legislation and contracts that would provide significant financial support for their reactor operations (for details see WNISR2018—Annex 4). In addition to legislation that has been enacted in New York and Illinois, new policies have been implemented in Connecticut and New Jersey, while efforts are ongoing to secure funding mechanisms continue in Pennsylvania and Ohio. Central to the future of nuclear power in the Pennsylvania-New Jersey-Maryland Interconnection LLC (PJM) wholesale electricity market are the rules expected to be proposed by the Federal Energy Regulatory Commission (FERC).468 PJM is a Regional Transmission Organization (RTO) that coordinates the wholesale electricity market in all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia. In June 2018, FERC invalidated the PJM market rules.469 The FERC order relates to how the PJM sets the price of capacity it procures through its capacity market, known as the Reliability Pricing Model (RPM). As state subsidies, including Zero Emission Credits or ZECs, have evolved from small-scale renewables to thousands of megawatts from larger nuclear units, FERC noted: “With each such subsidy, the market becomes less grounded in fundamental principles of supply and demand.”470 The next PJM capacity market auction will take place in August 2019.471 As of 1 July 2019 the rule changes from FERC have not been issued. They will affect how state subsidies, including ZECs, will be considered in the wholesale market. At issue is whether the subsidies being received by utilities for their nuclear plants will be factored into the capacity auction pricing. The PJM stated that pending new rules from FERC it will hold the August auction under current rules.472

As a result of securing financial support for reactors, it is likely that “early closures” of several additional reactors will be cancelled (see Table 9).

In December 2018, Dominion secured approval to gain subsidies for its two reactors at Millstone in Connecticut. Existing generating capacity in the state, such as the Millstone plant, cannot be credited for its zero-carbon and other environmental attributes unless it is designated by state regulators as being at risk of early closure. Dominion applied for that status for Millstone and received it in early December 2018. Prior to this approval, under the Low and Zero Emissions Renewable Energy Credit Program only renewable energy was eligible. Dominion threatened to close Millstone early unless recognized as a renewable source. In December 2018, Dominion got state approval to purchase just over 50 percent of the Millstone output over a period of ten years but without setting a contract price. The state had passed in November 2017 legislation that secured just under 50 percent of Millstone’s output over a ten-year period.

Dominion in early 2019 continued to lobby over pricing473 and on 15 March 2019, Dominion announced that it had reached agreement with state utilities and therefore would not be closing the Millstone reactors.474

Sources: Various, compiled by WNISR, 2019

Notes

a - See Pamela King, “SUPREME COURT—The fight's not over yet on state nuclear credits”, E&ENews, 16 April 2019,
see https://www.eenews.net/stories/1060166933, accessed 12 July 2019.

b - RTO Insiders, “NJ Approves $300M ZECs for Salem, Hope Creek Nukes”, 19 April 2019,
see https://rtoinsider.com/nj-approves-zecs-nukes-114741/, accessed 15 July 2019.

c - ProPublica, “New Jersey’s $300 Million Nuclear Power Bailout Is Facing a Court Challenge. Does It Have a Chance?", 16 May 2019,
see https://www.propublica.org/article/new-jerseys-300-million-nuclear-power-bailout-is-facing-a-court-challenge-does-it-have-a-chance, accessed 13 July 2019.

d - Robert Walton, “Dominion threatens Millstone closure if plant shut out of support program”, Utility Dive, 10 July 2018,
see https://www.utilitydive.com/news/dominion-threatens-millstone-closure-if-plant-shut-out-of-support-program/527364/, accessed 12 July 2018.

e - FirstEnergy has announced that it will begin the process to rescind the deactivation orders for its Perry and Davis Besse reactors.
See FirstEnergy Solutions, "FirstEnergy Solutions Applauds Enactment of HB6 Legislation", 24 July 2019, op. cit.

The Millstone nuclear plant was listed in 2017 as the most profitable in the U.S. through 2019, at US$14/MWh.475 Yet Dominion used the threat of closure of Millstone as leverage to secure state support. In a 2017 study commissioned by the Stop the Millstone Payout coalition, a group composed of competitive energy companies—NRG, Calpine and Dynegy and the Electric Power Supply Association (EPSA)—challenged Dominion’s claims. The study showed that state support for Millstone would cost ratepayers US$330 million per year, translating to a 15–20 percent increase in supply costs.476

Exelon Generation communicated in February 2019, that its three nuclear plants in Illinois, Braidwood, Byron and Dresden were

…showing increased signs of economic distress, which could lead to an early retirement, in a market that does not currently compensate them for their unique contribution to grid resiliency and their ability to produce large amounts of energy without carbon and air pollution. The May 2018 PJM capacity auction for the 2021-2022 planning year resulted in the largest volume of nuclear capacity ever not selected in the auction, including all of Dresden, and portions of Byron and Braidwood. Exelon continues to work with stakeholders on state policy solutions, while also advocating for broader market reforms at the regional and federal level.477

As noted by Nucleonics Week (NW), “The company had not previously said publicly that those plants were at risk of early closure.”478

In January 2018, Exelon had already secured Zero Emissions Credits for its Quad Cities and Clinton reactors, which equates to a cumulative value over the expected life of the ZEC contracts, without any adjustments, of US$3.5 billion.479 Currently, its Dresden, Byron and Braidwood reactors with an installed capacity of 6.9 GW, are not eligible for ZECs, as the existing support for Quad Cities and Clinton “fill[s] up the scope of the existing ZEC program under Illinois law”.480

Legal efforts to overturn ZEC contracts in Illinois (and New York) were rejected by the Supreme Court on 14 April 2019.481 As WNISR2018 reported, the Electric Power Supply Association (EPSA) had filed a complaint in the U.S. District Court of the Northern District of Illinois opposing the proposed ZECs for Exelon, stating that “bailing out uneconomic power plants is a bad deal for Illinois ratepayers, who will see their electric bills go up across the state”.482

The Supreme Court ruling follows federal appeals court rulings in New York483 and Illinois484 during September 2018, which endorsed the constitutional rights of states to establish financing for generators and to regulate electricity prices. By doing so the courts have rejected contentions that support for nuclear power by state legislation (such as ZECs) influences the prices that result from the wholesale auction system established by the Federal Energy Regulatory Commission (FERC) and therefore distorts the market mechanism for determining which energy generators should close.485 Lawyers observed that the rulings do not resolve the underlying tensions between state subsidies and wholesale electricity markets.486

On 18 April 2019, the New Jersey Board of Public Utilities (NJBPU) awarded Zero Emission Certificates (ZECs)487 to Salem-1 and -2 and Hope Creek reactors.488 The State Legislature passed the Zero Emissions Certificate Law in May 2018489, noting the “moral imperative for the State to invest in energy infrastructure that does not produce greenhouse gases.”490 Welcoming the decision, Public Service Enterprise Group (PSEG) stated that, “We are pleased with the decision to award ZECs to PSEG to help support New Jersey’s primary supply of zero-carbon electricity. The BPU just saved the people of the State hundreds of millions of dollars in what would have been higher energy costs, thousands of jobs lost and tons of environmentally damaging air emissions.”491 Opposition to the ZEC legislation, including from New Jersey’s Ratepayer Advocate and a generators’ group in the Pennsylvania-New Jersey-Maryland Interconnection LLC (PJM) market, said there is no evidence three nuclear units in New Jersey need ratepayer subsidies to survive.492 In testimony to the Board, from State Rate Counsel President Stephanie Brand it was stated that modeling used by the utilities in the subsidy application did not account for the addition of renewable energy resources over the long term or increased energy efficiency requirements: “In short, they skewed the analysis of future revenues in order to deflate those revenues and support their claim 3 of financial distress.”493

The data suggests that the ZEC Act would require New Jersey electric distribution companies (“EDC”) to collect approximately [US]$300 million per year from New Jersey retail distribution customers based on annual data. This amount would be incremental to charges collected from distribution customers and transmission for other programs. For the three nuclear units, the ZEC Act would result in a [US]$10/MWh revenue adder for each unit’s owner if the Board approves the three applications… The ZEC Act allows the Applicants, who are merchant owners, to cover costs—including the cost of capital. 494

The credits were to be available immediately, which will net approximately US$10/MWh amounting to US$100 million in subsidies per year for each reactor through 2022. The two units at Salem owned by Public Service Enterprise Group (PSEG) subsidiary PSEG Nuclear and 43 percent by Exelon are licensed by the Nuclear Regulatory Commission (NRC) to operate until 2036 and 2040. Hope Creek is licensed to operate until 2046.

For the third time in as many years, FirstEnergy Solutions has sought to secure state financing for its reactors in Ohio. Both Davis Besse and Perry reactors are long considered at risk of closure due to economic factors.495 On 31 March 2018, FirstEnergy Solutions Corp. and six affiliated debtors each filed a voluntary petition for protection under Chapter 11 of the United States Bankruptcy Code in the Bankruptcy Court for the Northern District of Ohio.496 The company is currently under petition at the NRC due to its failure to secure sufficient decommissioning funds for its three nuclear plants.497 A 2017-estimate put decommissioning costs for the three nuclear plants at US$5.4 billion, with a current fund level of only US$2.5 billion.498 In April 2018, First Energy filed official notification with the NRC of its bankruptcy and planned closure of Beaver Valley (Pennsylvania), as well as the two reactors at Davis Besse and Perry in Ohio.499 First Energy noted: “We are actively seeking policy solutions at the state and federal level as an alternative to retiring these plants, which we believe still have a crucial role to play in the reliability and resilience of our regional grid.”500 but that “short of significant market changes... right now, we have nothing in front of us that allows us to rescind that deactivation notice.”501 FirstEnergy’s debts amounted to US$2.8 billion.502

The decision of FirstEnergy Solutions is a further signal that just because reactors have obtained 20-year license extensions does not mean they will operate through the full license period. The Beaver Valley Units 1 and 2 in 2009 were issued by the NRC 20-year license extensions to permit them to operate until 2036 and 2047 respectively.503 FirstEnergy had notified the NRC only in May 2017 that it planned to file a license extension in 2020 for the one Perry reactor, whose current license expires in 2026. The 42-year-old Davis-Besse reactor was granted an NRC license extension in 2015, to operate through 2037.504

“ Despite bankruptcy filings in 2018, FirstEnergy continued to spend millions of dollars on lobbying and advertising ”

FirstEnergy’s power purchase agreement approved in March 2016505 was blocked by the Federal Energy Regulatory Commission (FERC) a month later. Through 2016 and 2017, FirstEnergy then continued to lobby for the establishment of Zero Emission Nuclear (ZEN) legislation that would support their Davis Besse and Perry reactors, which could be worth an estimated US$300 million a year to their owners. In October 2017, a fresh bill was introduced, the ZEN resource program, aimed at saving the Davis Besse and Perry reactors, leading FirstEnergy to claim that it “would increase the likelihood of keeping the plants operational throughout the life of the program.”506 The bill reduces the amount FirstEnergy would receive over two consecutive periods of six years, from US$300 million in previous introduced legislation to US$180 million.507 The Perry reactor was expected to operate at a profit of US$3.5/MWh during 2017–2019, with Davis Besse at US$4.5/MWh through the same period. These figures do not include the additional income if Ohio’s emissions credits are finally approved.

The proposed legislation made no progress during the year 2018, despite appeals by the bill’s sponsor to move forward following FirstEnergy’s filing for bankruptcy.508

Despite bankruptcy filings in 2018, FirstEnergy continued to spend millions of dollars on lobbying and advertising in efforts to secure favorable legislative changes in Ohio and Pennsylvania.509 In spring 2019, the Ohio legislature introduced the House Bill 6 or HB6, which would create the Ohio Clean Air Program and provide “clean energy” credits to zero-emission power producers, including Davis Besse and Perry plants.510 Financing is proposed through the Ohio Clean Air Fund. Amendments made to the Bill by Republican sponsors meant that by 28 May 2019 it was clear that the primary beneficiary of the legislation will be FirstEnergy. The estimated US$197.6 million that would be charged in new ratepayer fees would largely be paid to FirstEnergy. Renewable energy companies will not be able to access the Ohio Clean Air Program, with only small domestic wind turbines being eligible. Legislatures have also proposed terminating existing programs that encourage electricity providers to purchase renewable energy as well as energy efficiency programs. Finally, coal power with sequestration would be eligible for financing.

The proposed HB6 and its effective termination of support for significant renewable energy programs and energy efficiency—while instead supporting coal plants in Ohio—runs counter to those who have argued that ZEC support for nuclear plants is a necessary part of an eventual transition to renewable energy. This includes the United States Court of Appeals for the Second Circuit, which in September 2018 stated that in the case of New York, “the ZEC program aims to prevent nuclear generators that do not emit carbon dioxide from retiring until renewable sources of energy can pick up the slack.”511

HB6 charges Ohioans a US$1 fee each month starting in January 2021 for nuclear energy. The fee is higher for businesses (US$15) and industrial customers (US$250 to US$2,500). The fees would in early versions of the legislation be applied for five years through 2026, but amendments by House Republicans would lock in the charges until 2030.512 It has been estimated that these subsidies would net EnergySolutions US$320 million each year for its two nuclear plants. As reported in Ohio, the bailout of FirstEnergy is nothing new. Since 1999, FirstEnergy has received US$10.2 billion in state subsidies.513

Opposition to the legislation included the Chair of the Energy Generation Committee, and the Energy and Natural Resources Committee:

This is a bailout plain and simple. What has happened is that First Energy and First Energy Solutions, they’re in bankruptcy and they need a bailout. (…) Everyone will pay even if their electricity is not provided by nuclear power plants, everyone in Ohio will have to pay. First Energy has been bailed out before.514

On 13 May 2019, analysis of the economics of Davis Besse and Perry reactors argued that “The Ohio nuclear units are operating profitably in covering their going forward and avoidable costs and future capital expenditures. Consequently, there is no rational economic reason for them to retire.”515 The calculations of the reactors was based on unit specific costs, “whose relative accuracy has been verified by examining FirstEnergy financial statements in Securities and Exchange Commission (SEC) filings.”516 This is in contrast to the PJM that uses industry average single unit costs.

FirstEnergy rejected the analysis, citing that it “excludes critical cost components” including capital spending requirements and ignores the fact that the plants did not clear PJM’s 2021/2022 capacity auction and will likely not clear future auctions. The power provider said that fixing the consultant’s “obvious calculation errors” results in a net loss of more than $125 million/year versus a profit for the plants.517

The justification for the HB6 legislation was also challenged in a May 2019 analysis from the Institute for Energy Economics and Financial Analysis (IEEFA).518 It concluded that “FirstEnergy’s nuclear and coal plants are not needed to ensure electricity supply or reliability in Ohio”, and that terminating the reactors is “unlikely to drive up electricity rates in Ohio—but reducing energy efficiency and renewable energy could have that effect.” IEEFA contended that, “If Ohio is serious about providing low cost sources of clean energy, it would make more economic sense to invest in solar energy than to subsidize aging nuclear plants.”519

On 28 May 2019, the HB6 legislation was passed by the Ohio House.520 FirstEnergy was hoping that approval by the Senate would take place during June 2019, before the end of the current legislative sessions and when the utility was to decide whether to proceed with plans for refueling of the Davis Besse reactor, which was scheduled for closure in 2020. Securing HB6 would also likely see reversal of the decision to close Perry in 2021. While the legislature ended on 28 June 2019, before the Senate could vote on HB6, additional dates were added to the session. On 17 July 2019 the Senate passed HB6,521 and on 23 July 2019 the House also voted to approve the Senate version of the legislation.522 The Governor of Ohio signed the legislation into law the same day. Welcoming the legislation, FirstEnergy Solutions announced that it will “begin the process to rescind the deactivation orders for its Perry and Davis-Besse nuclear power stations and immediately resume preparation for the mandatory Davis-Besse refueling outage in the Spring.”523

The final version of HB6 will mean that from April 2021 through 2027, FirstEnergy Solutions will receive quarterly payments that will net on average US$150 million each year from additional electricity charges on domestic and industrial customers. An additional nearly US$50 million a year will be received by Ohio Valley Electric Corp to operate two old coal plants in the state.524 In addition, energy-efficiency standards will end for each utility in Ohio once it achieves a 17.5-percent power reduction while also reducing the state’s renewable-energy target from a maximum of 12.5 percent by 2027 to 8.5 percent by 2026—the level that, under current law, utilities must reach by 2022.525 The American Wind Energy Association stated: “Ohio consumers and manufacturers want greater commitment to renewable energy, not less...(it) won’t make Ohio’s air cleaner, but it will hike consumer electric bills and send both jobs and clean energy investment to Ohio’s neighbors”.526 HB6 arguably sets a new standard for costly and asymmetrical state action to bail out failing coal and nuclear investments while disadvantaging efficiency and renewables.

In Pennsylvania, while legislative initiatives failed in 2018 to secure bailouts of nuclear plant operators, efforts continued during the past year. A contentious debate has been underway over the extent to which Exelon and FirstEnergy are seeking state support for their reactors in the state citing unfavorable market conditions, while at the same time failing to disclose detailed financial statements on grounds of commercial sensitivity. In May 2017, Exelon had announced that TMI-1, scheduled for closure in September 2019, and Quad Cities in Illinois, for the third year running, had not cleared the PJM base residual auctions. With FirstEnergy’s Beaver Valley-1 and -2 planned closures in May and October 2021 respectively,527 total closures in Pennsylvania would represent 25 percent of the state’s nuclear generating capacity, but only 6 percent of the state’s overall power generation.

One analysis released in March 2019 provided insight into the economics of TMI and Beaver Valley nuclear plants operating in Pennsylvania.528 In the case of Exelon’s TMI-1, it reported that losses for 2018 were likely to be in the range of US$73 million; FirstEnergy’s twin Beaver Valley units were found profitable by US$23–96 million per year depending on whether they cleared the PJM auction, but could be as high as US$173 million if based on the day-ahead average Locational Marginal Price (LMP).

The PJM Interconnection in a 5 June 2019 analysis concluded that there would be “no reliability impact from the planned closures of the Davis Besse, Perry and Beaver Valley nuclear units... [however] it can reasonably be expected that imposing additional out-of-market subsidies to retain generation that would otherwise retire would have a chilling effect on new investment in the longer term.”529

Two legislative efforts were underway in the Pennsylvania House and Senate in early 2019.530 In March 2019 an amendment was proposed to the 2004 Alternative Energy Portfolio Standards (AEPS) Act that would provide financial support to the state’s nuclear plants, which were currently excluded.531 The principal sponsor of the bill made the case that “If we lose one or more of these plants we might as well forget about all the time and money we’ve invested in wind and solar. [...] The Legislature can save Pennsylvania consumers money, keep our nuclear power plants open and keep our air clean.”532 In contrast, the Natural Resources Defense Council (NRDC) condemned the draft bill as

…nothing more than a windfall for aging, uneconomical nuclear power plants. It fails to limit carbon pollution or advance commonsense energy policy that transitions Pennsylvania away from nuclear power and dirty fossil fuels to renewable sources and energy efficiency.533

Hearings began in April 2019, with both proponents and opponents contesting the benefits and detriments of the legislation.534 The state’s Public Utility Commission (PUC) has estimated that the legislation if adopted would cost ratepayers between US$459 and US$551 million a year in subsidies to FirstEnergy and Exelon.535 This estimate was on the basis that both TMI-1 and Beaver Valley would be operating, which will no longer be the case as Exelon Generation announced on 8 May 2019 that TMI-1 will permanently close by 30 September 2019.536 As of 1 July 2019, legislation had yet to be approved.

Fukushima Status Report

Introduction

Eight years have passed since the Fukushima accident began in March 2011. Spent fuel removal in Unit 3 has started following significant delays and the investigation to locate fuel debris in Unit 2 was finally conducted, but with uncertain results. Although the evacuation order of a part of the evacuation zone was lifted again, only few residents have returned.

The assessment of health consequences remains controversial. Thyroid cancer in children continues to increase, with ongoing controversies over the causal relationship with the accident.

Other areas analyzed in this chapter are remaining food contamination, storage of contaminated water and the management of decontamination wastes that continue to accumulate.

Onsite Challenges

Current Status Reactors537

Water injection into all three units with fuel debris—Units 1, 2 and 3—has been continuing; the temperature of the lower part of the reactor pressure vessels and the containment vessels is currently maintained at 15–25 degrees Celsius. According to the survey map538 of radiation doses, the levels measured across most of the site are below 10 μSv/h (micro-sievert per hour) but there are locations with levels of 100 μSv/h near the buildings.539 The dose inside the reactor buildings is still high; the level at some locations is more than 10 mSv/h.540 The amount of radioactive materials released from the reactor building is about 5×10-12 Bq/cm3 for Cs-134 and about 3.5×10-11 Bq/cm3 for Cs-137 at the site boundary. These values are below the air concentration limits set by the Japanese government.541

In April 2019 the work of spent fuel removal finally re-started after having been halted since the work at Unit 4 was completed in December 2014.542 Removal of spent nuclear fuel, comprising 566 fuel assemblies, at Unit 3 began on 15 April 2019. Since it was scheduled to start in the middle of 2018 in the government’s medium- and long-term roadmap,543 this was a delay of about half a year.544 It is reported that the plan was delayed due to malfunction of the machine that transfers the spent fuel to the transport container. The spent fuel will be moved to and stored in the common spent fuel pool. This work is scheduled to take about one year until FY 2020.

At Unit 1 the removal of debris, which is an obstacle to the removal of spent fuel, was finally completed in February 2019. As for Unit 2, the process is still at the stage of designing the fuel removal method. In the most recent Tokyo Electric Power Company (TEPCO) roadmap report,545 the plan has been significantly revised. Instead of removing the roof and walls of Unit 2, the existing fuel handling machine is to be repaired, and then in combination with a new rig, spent fuel containers will be removed via the air lock platform newly installed in Unit 2.

In the roadmap, the removal of spent fuel in Unit 1 and 2 is scheduled to start in Financial Year (FY) 2023.

With regard to the removal of molten fuel debris, it is scheduled in the roadmap to determine the removal method for the first unit in FY 2019. However, as of 1 July 2019, there has been no official announcement. According to the Fukushima Daiichi decommissioning roadmap, the fuel debris removal from the first unit will start by 2021 and be completed within ten years. The timetable for the plan lacks credibility. The International Research Institute for Nuclear Decommissioning (IRID) has estimated a range of volumes of molten fuel in the three reactors:546 for Unit 1, 232–357 tons, with a nominal value of 279 tons; Unit 2, 189–390 tons, with a nominal value of 237 tons; and Unit 3, 188–394 tons, with a nominal value of 364 tons. The reason that the corium mass is higher than the original fuel mass—69 tons in reactor 1, and 94 tons in each of reactors 2 and 3—is that corium contains, in addition to the original fuel, molten steel and concrete. Consequently, the corium masses are 2.5–4 times larger than the original fuel. The sum of the nominal quantities of corium is 880 tons, with the lower range being 609 tons, and upper estimate being 1,141 tons. This nominal value of 880 tons is 3.4 times more than the original fuel in the three reactors.

On 13 February 2019, for the first time, a survey robot made direct contact with material in the Reactor Pressure Vessel (RPV) of Unit 2.547 The maximum measurement of the dose at the bottom of the containment vessel remains a lethal 43 Sv/h.548 While TEPCO had earlier predicted that the material at the bottom of the RPV was molten fuel debris, the result of the inspection has raised many questions as to the location and condition of the molten fuel in Unit 2. Radiation levels measured 30 cm from the material was recorded at 7 Sv/h, rather than several hundred Sv/h anticipated by TEPCO. This led to questions not just over the amount of molten fuel remaining in the RPV and therefore how much has exited the RPV into the basemat, but most significantly whether in fact all the molten fuel will in the end be removed. The material that was lifted by a robotic arm in the February 2019 survey comprised mostly of pebble-like sediment, with speculation that this included zirconium cladding. Further inspections are scheduled for the second half of 2019. As a result of the February inspection, Akira Ono, head of the Fukushima Daiichi decommissioning project, stated on 28 March 2019 that “At present, it is difficult to clearly say we are going to remove all fuel debris”.549,550

The inspection results of Unit 2 prompted Naoyuki Takaki, professor of nuclear engineering at Tokyo City University, to state that “there could ultimately be a decision to stop debris removal after pulling out as much debris as possible. In that case, we would have no option but to consider building a sarcophagus like the one at the Chernobyl nuclear plant.”551 There has been no change to the planned decommissioning completion period, which is set at 2041 to 2051.

Contaminated Water Management

The implementation of response measures for the contaminated water552 is still ongoing. With regards to the frozen soil walls (land-side impermeable walls553), for which feasibility and high cost were considered to be a problem, TEPCO claimed that the walls had almost been completed in March 2018.554 Many measures—such as pumping up of groundwater before it flows into frozen soil walls and buildings—have reduced the amount of groundwater and rainwater flowing into buildings; as a result, the amount of newly generated contaminated water has decreased, but remains significant. The average quantity of contaminated water was about 470 m3/day in FY 2014 and decreased to about 170 m3/day in FY 2018.555 In the roadmap, the goal is to curb the amount to 150 m3/day by 2020.

As for this contaminated water, the work for removing radioactive materials from the water has been continued using multi-nuclide removal equipment and other devices. The treated, still contaminated water—containing tritium in particular, the only material that is not planned to be removed—continues to be stored in storage tanks. As of 21 March 2019, the total storage volume in the tanks is about 1.12 million m3. The current plan is to increase the total tank storage capacity to 1.37 million m3 by the end of 2020.556 If the capacity is enhanced, the difference would be 250,000 m3, which would extend the capacity by about four years, at a production rate of 170 m3/day. However, if the capacity of the storage tanks is 1,000 m3 per tank, a new tank is still needed about every six days.

The Nuclear Regulatory Authority (NRA) recommends dumping the contaminated water into the ocean, but TEPCO has not decided on its final disposal method because of fear of backlash from local residents. The Ministry of Economy, Trade and Industry (METI) held public hearings on the future handling of treated water containing tritium in August 2018 in Fukushima Prefecture and Tokyo.557 However, most of the participants including the representatives of the fishermen’s co-op raised concerns about reputational damage and safety.558

A major setback to plans for discharge into the Pacific Ocean emerged in August 2018, when it was reported by Kyodo News that TEPCO’s Advanced Liquid Processing System (ALPS) had not performed as had been widely reported otherwise.559 On 28 September 2018, TEPCO admitted that of the 890,000 m3 of water treated by the ALPS (as of September 2018) and stored in tanks, about 750,000 m3 tons contained higher concentrations of radioactive materials than levels permitted by the safety regulations for release into the ocean.560 In 65,000 m3 of treated water, the levels of strontium-90 are more than 100 times above the safety standards, according to TEPCO. In some tanks, the levels are exceeding the limits by a factor of 20,000. These admissions contrast with earlier official statements on ALPS, claiming the system would reduce radioactivity levels “to lower than the permissible level for release”.561

The disclosures from TEPCO further antagonized local communities. The METI contaminated-water task-force is currently reviewing the implications of these disclosures and how to proceed with management of the contaminated water. TEPCO indicated that it will be necessary to conduct further processing of the contaminated water, which could take several years.562

Coastal fishermen in Fukushima prefecture are currently voluntarily refraining from fishing activities within 10 km of the Fukushima Daiichi plant. However, identified marine products with levels exceeding the contaminated threshold (100 Bq/kg) are decreasing,563 and the fishermen are currently operating on a trial basis, i.e., they are fishing and selling some fish species for which safety has been confirmed. Their concern is that a decision to release tritiated water into the Pacific would have a major impact on their attempts to restore their fragile fishing businesses.564,565

The International Atomic Energy Agency (IAEA) has reviewed METI for its decommissioning efforts. In the final report of its fourth review (5–13 November 2018),566 the IAEA highlights that storage in tanks is only a temporary measure and that sustainable options are needed.567 At the same time, the IAEA has long argued for a Pacific Ocean release.

Worker Exposure

According to TEPCO, the monthly average workers’ radiation dose was about 0.36 mSv in FY 2017, a decline from about 0.59 mSv in FY 2015. The burden on employees of subcontractor companies is large. The number of workers in February 2019 was 7,264, of which 962 TEPCO employees and 6,302 employees from subcontractors.568 The maximum effective dose for external exposure was 5.38 mSv for TEPCO employees and twice as high or 10.87 mSv for subcontractor employees.

According to the questionnaire survey involving workers other than TEPCO employees conducted by TEPCO and released in December 2018,569 41.9 percent of the workers responded that they felt “anxious.” The reasons given for such anxiety included “the impact of [radiation] exposure on health.” The Ministry of Health, Labor and Welfare (MHLW) supervised and gave guidance to 290 business operators who carried out decommissioning work, of which more than half (154) were in violation of labor laws. The rate of detected infringements was 53.1 percent, up from 38.4 percent in the previous fiscal year.570 The most frequent type of violation was inadequate payment of premium wages.

According to multiple newspapers,571 MHLW recognized the decommissioning work of the Fukushima accident as the cause of cancer developed by two workers. The causal relationship between radiation exposure and illness was recognized for one of them on 4 September 2018. This employee of a subcontractor company was in charge of radiation control at multiple nuclear power plants from 1980 to September 2015. After the Fukushima accident started in March 2011, he was in charge of measuring the radiation dose of locations slated for decontamination prior to implementation. He was diagnosed with lung cancer in February 2016 and subsequently died. His cumulative dose was estimated at 195 mSv, of which about 74 mSv was from exposure after 3/11.572,573

The other worker was also a subcontractor company employee for whom causal relationship between radiation exposure and illness was recognized on 12 December 2018. For about 11 years, between November 1993 and March 2011, he had been working in the maintenance of electrical facilities at several nuclear power plants. Immediately after 3/11, he started carrying out restoration work of the power supply. In June 2017, he was diagnosed with thyroid cancer. His cumulative exposure dose was estimated at 108 mSv of which about 100 mSv were due to post-3/11 exposure, including about 37 mSv calculated to be internal exposure.574,575 As a result, so far the Fukushima events have been recognized by MHLW as the cause of cancer for six people: two cases of thyroid cancer, three cases of leukemia, and one case of lung cancer.

In addition, death caused by overwork also occurred. The cause of one worker’s death was recognized by the MHLW as overwork in November 2018 while TEPCO had claimed at a press conference the day after his death in October 2017576 that there was no causal relationship with the work.577

The MHLW has commissioned an epidemiological survey of workers.578 As of April 2019, the first cycle of the baseline survey, which examines the health condition and smoking habits of the examinees, has finally ended. However, prospective subjects are reluctant to participate in the survey. As of 15 January 2018, out of the 19,808 prospective subjects, 6,873 have participated in the survey (34.7 percent), 3,432 have refused to participate (17.3 percent), 7,392 have not replied (37.3 percent), and the contact information was unavailable for 1,685 (8.5 percent).579 According to media reports, it is believed that a strong distrust of TEPCO and the government is the main reason why the number of participants is so low.580

Offsite Challenges

Current Status of Evacuation

As of 5 April 2019, 39,724 Fukushima residents are still living as officially designated evacuees (7,235 are living in the prefecture, 32,476 are living outside the prefecture, and 13 are missing).581 According to Fukushima Prefecture, the peak level of evacuees was 164,865 (May 2012).582 The official figures do not include the so-called “self-evacuees” who left areas of Fukushima that were outside the officially designated evacuation areas. As of October 2016, the official figure for these evacuees was 26,601.583 Starting in 2017, Fukushima Prefecture no longer included these evacuees in its statistics.

The government has continued its policy of lifting evacuation orders in the remaining evacuation zones.584 On 10 April 2019, for the first time in two years, evacuation orders were lifted for a Restricted Residence Zone585 and a Zone in Preparation for Lifting the Evacuation Order586. The location where the evacuation orders were lifted this time is a part of Okuma Town, one of the host towns for the Fukushima Daiichi plant.587

However, population numbers have not significantly increased in areas where evacuation orders have been lifted. According to the latest residents’ intention survey by the Reconstruction Agency, for example, only 4.9 percent of the residents of Namie Town588 have returned and 49.9 percent of the residents have already decided not to return to the town.

The treatment of voluntary evacuees589 is worsening. Fukushima Prefecture stopped providing free housing for voluntary evacuees at the end of March 2017 and although the prefecture subsequently started providing rent assistance for low-income households, this assistance was also terminated at the end of March 2019590. Once the free housing offer is terminated, they are no longer considered as voluntary evacuees and they disappear from the statistics of evacuees. The Governor of Fukushima Prefecture has not given a clear answer to the question from a reporter regarding the necessity of conducting a fact-finding investigation into their situation.591 These voluntary evacuees may eventually consider returning to Fukushima as a result of being denied the right to evacuate, something the government and Fukushima Prefecture are effectively trying to force on tens of thousands of Japanese citizens. In its recovery plan, Fukushima Prefecture has set a goal to reduce the number of evacuees inside and outside the prefecture to zero within FY 2020.592 On current trends it will miss this target by a wide margin.

On 25 October 2018, at the UN General Assembly, Special Rapporteurs from the UN Human Rights Commission criticized the Japanese government’s policies as it relates to evacuees.593 The UN Rapporteurs pointed out that the conditions for lifting evacuation orders should be a radiological situation limiting exposure to 1 mSv/year instead of the government-designated 20 mSv/year. In addition, they expressed strong concerns about evacuees being pressured to return due to the termination of free housing support. However, the Japanese Ministry of Foreign Affairs has argued that, “The Government of Japan is seriously concerned about such claims, as it could unnecessarily inflame public anxiety, cause confusion, and further trouble people suffering from reputational damage in disaster-hit areas.”594

In August 2018, UN Special Rapporteurs also raised multiple issues of human rights violations around the Fukushima Daiichi plant, including families with children, and involving decontamination workers.595

According to the Reconstruction Agency, as of the end of March 2019, there were approximately 51,000 evacuees of the Great East Japan Earthquake in Japan as a whole, including the 39,000 official “nuclear” evacuees.596 Evacuees were primarily from Miyagi, Iwate and Fukushima Prefectures, which were seriously damaged by this magnitude 9 earthquake and tsunami. Although time has passed since the earthquake and these prefectures are in the process of restoration, Fukushima Prefecture alone has different characteristics from the other two prefectures. The total number of evacuees in and outside the prefecture decreased to 4,466 in Iwate Prefecture and 6,159 in Miyagi Prefecture as of the end of March 2019. However, the pace of reduction has been slow in Fukushima Prefecture; the prefecture still counts 41,454 evacuees. As shown in Figure 34, the number of evacuees reported in Fukushima Prefecture fell sharply in 2017 when, as noted above, free housing for voluntary evacuees was cut off and they were removed from the database.

Indirect but disaster-related deaths remain a cause of major concern.597 Fukushima Prefecture is still showing an increasing trend (see Figure 35).598

Source: Compiled by Tadahiro Katsuta, based on Reconstruction Agency, “Change in the number of evacuees”, 2019.

The termination of the compensation for damages is also a problem. For example, according to the guidelines for damages set forth by the Dispute Reconciliation Committee for Nuclear Damage Compensation,599 compensations paid for psychological damages end one financial year after a relevant evacuation order is lifted (for restricted residential zones and zones in preparation for lifting the evacuation order). For example, in Tomioka-cho, for which the evacuation order was lifted two years ago, the compensation ended in March 2019.

Victims of the nuclear accident can file a claim with the Alternative Dispute Resolution (ADR) Center for Nuclear Damage Dispute Settlement. The ADR Center proposes to victims and TEPCO a settlement compromise (settlement amount). TEPCO is still paying compensation for damages, and as of 19 April 2019, the total payment has reached approximately 8,972 billion yen (US$81.5 billion600).601 The total number of claims for damages from individuals and corporations is about 3 million.

Source: Compiled by Tadahiro Katsuta, based on Reconstruction Agency, “Number of disaster-related deaths of the Great East Japan Earthquake”, 2019.

TEPCO has made three pledges in its business plan: “Complete compensation payments up to the very last person”, “rapid and thorough compensation” and “respect of intermediate settlement proposals”.602 However, TEPCO continues to reject the settlement proposals of many collective complaints against the company’s compensation practice. For example, Namie Town filed a collective complaint in 2013 on behalf of more than 15,000 town inhabitants. The complaint called for a uniform increase, noting that the amount of compensation was not appropriate for the reality of peoples’ damages. However, as TEPCO continued to reject the settlement proposal, the settlement mediation by the ADR Center was discontinued in April 2018.603 In November 2018, Namie Town filed a lawsuit against TEPCO and the Japanese government.604

As a result of persistent efforts of lawyers representing 13,000 Japanese citizens, criminal trials have been held since 2017 against three former TEPCO executives (the former Chair of TEPCO and two former vice presidents) on charges of professional negligence resulting in death and injury. The trial has been ongoing, with sentencing scheduled for 19 September 2019. 605 If found guilty, the executives could see five-year prison sentences (though unlikely). Such an outcome would have widespread ramifications in Japan, not just for ongoing legal actions, but for the future prospects for TEPCO’s nuclear operations now centered on the Kashiwazaki Kariwa reactors.

Radiation Exposure and Health Effects

Fukushima Prefecture has been continuing its thyroid cancer examination program for children who were under 18 years old at the time of the accident.606 As of April 2019, the number of patients diagnosed with a malignant tumor or suspected of having a malignant tumor is 212; 169 individuals underwent surgery (see Table 10).607

Even now, the Prefectural Oversight Committee Meeting for Fukushima Health Management Survey does not recognize the causal relationship between the occurrence of thyroid cancer and radiation exposure post-3/11. However, analysis based on previous examinations is being carried out. In February 2019, referring to the report of the United Nations Scientific Committee on the Effects of Atomic Radiation (UNSCEAR), the oversight committee reported that there would be no increase in cancer detection rate associated with the increase in radiation dose.608 However, due to the high uncertainty of this UNSCEAR report, the oversight committee decided to continue the analysis instead of drawing any final conclusions.

Source: Compiled by WNISR based on Fukushima Prefecture, “The 34th Prefectural oversight committee meeting for Fukushima health management survey, Reference 1, Status of thyroid test results”, 8 April 2019 (in Japanese).

Food Contamination

During the year ending March 2019, according to the official statistics, among 299,500 sample measurements conducted for food contamination across the country, 313 food items were identified that exceeded the threshold.609, 610 Fukushima Prefecture has the highest number of those detections (125 items). For example, some bamboo shoots and wild boar meat exceeded the threshold. The number of detected items has increased compared to that of FY 2017 (200 items). According to the Ministry of Health, Labor and Welfare (MHLW), inspections have been conducted prior to shipment and most of the contaminated food items have been found in areas under shipment restriction.

The Consumer Agency continues to investigate reputational damage. According to a March 2019 survey, among those who care about the production area at the time of food purchase, the portion of people wishing to buy food stuffs that do not contain radioactive substances was 15.6 percent, a significant drop from 27.9 percent in February 2013.611 However, on the other hand, the number of people who are not aware of food inspections such as shipping restrictions increased from 22.4 percent in 2015 to 44.8 percent. The reduction in reputational damage, as demonstrated by these results, may be because people’s memory of the Fukushima accident itself has faded, or that they have given up on safety, rather than a consequence of people gaining a better understanding of radioactivity.

On the other hand, the impact of 3/11 on food exports is still severe. The Japanese government filed a complaint with the World Trade Organization (WTO) on the grounds that South Korea would arbitrarily and unfairly discriminate when importing Japanese food.612 Japan’s request was granted at the first trial held in 2018, but Japan lost the case at the Appeals tribunal on 11 April 2019.613 As a result, South Korea has been able to continue its import restrictions on food produced in Japan.

After 3/11, 54 countries had imposed import restrictions and as of April 2019, the regulations remain in force in 23 countries. In particular, eight countries including South Korea, China, and the U.S. do not import from Fukushima Prefecture.614

Decontamination615,616

Decontamination of the Special Decontamination Area617 managed by the Japanese government in Fukushima Prefecture ended in March 2018, and work in the Intensive Contamination Survey Area618 ended already in March 2017. According to the Ministry of the Environment (MoE), a budget of about ¥2.9 trillion (US$26 billion) was spent on decontamination resulting in about 16.5 million m3 of contaminated soil and other waste.619 However, it cannot be said that dose rates in Fukushima Prefecture have returned to the situation prior to the Fukushima accident.620 The difficult-to-return zones have not been subject to decontamination. However, decontamination testing has been carried out.621

On 16 August 2018, the Special Rapporteur of the UN Human Rights Commission issued a statement warning that workers engaged in the cleanup of the Fukushima accident were at risk from radiation exposure and serious exploitation.622

The work of transferring contaminated soil from a temporary storage site in Fukushima Prefecture to an intermediate storage facility623 has been in progress since FY 2015. Although land acquisition for the facility has not yet ended, storage has begun in some areas.624 According to the MoE, the decontaminated soil to be transported is about 14 million m3. As of 19 April 2019, approximately 2.7 million m3 of decontaminated soil had been moved.625 In other words, only about 20 percent has been transported during the four-year period.

No plans have been developed for the final disposal of decontaminated soil out outside Fukushima Prefecture after 30 years of storage. The MoE plans reutilization of decontaminated soil, for example, on agricultural land as it is difficult to find a disposal site outside the prefecture. A demonstration project was planned to reuse the soil in road construction as embankment in Nihonmatsu City, Fukushima Prefecture, but it was canceled in June 2018 due to local opposition.626

As for contaminated soil outside the prefecture, 329,104 m3 of removed soil is stored at 28,026 locations and 142,859 m3 of waste is stored at 9,320 locations as of the end of March 2019.627 These are to be disposed of in landfills. As of March 2019, a demonstration test of landfill disposal is being conducted for about 641 m3 of soil/waste at the Tokai-mura Japan Atomic Energy Agency (JAEA) site in Ibaraki Prefecture, and about 217 m3 of soil/waste at an open space in Nasu Town, Tochigi Prefecture.628

Conclusion on Fukushima Status

The Japanese government and TEPCO are promoting highly controversial policies. Decommissioning work is leading to occupational diseases; evacuation orders are lifted but people do not wish to return; decontamination waste (soil)—collected by decontamination workers who were exposed—shall be reused. Thus Japan’s policies regarding the ongoing crisis at Fukushima, supposed to protect its people, appear to be implemented at the expense of its people.

Decommissioning Status Report 2019

Introduction and Overview

Decommissioning Worldwide

The defueling, deconstruction, and dismantling—summarized by the term decommissioning—are the final steps in the life cycle of a nuclear power plant. The process is technically complex and poses major challenges in terms of long-term planning, execution and financing. Decommissioning was rarely considered in the reactor design, and the costs for decommissioning at the end of the lifetime of a reactor were usually discounted away, and thus, subsequently, largely ignored. However, as an increasing number of nuclear facilities either reach the end of their operational lifetimes or are already closed, the challenges of reactor decommissioning are coming to the fore, and also attract increasing public attention.

Sources: compiled by WNISR, 2019

Note: PWR = Pressurized Water Reactor, BWR = Boiling Water Reactor, GCR = Gas Cooled Reactor, LWGR = Light Water Gas-Cooled Reactor,

PHWR = Pressurized High Water Reactor, FBR = Fast Breeder Reactor.

The cluster “other” includes the reactor technologies: High-Temperature Gas-Cooled Reactor (HTGR), Heavy Water Gas Cooled Reactor (HWGCR), Steam Generating Heavy Water Reactor (SGHWR), Heavy Water Light Water Reactor (HWLWR), and yet “others”.

As of 1 July 2019, worldwide, there are 181 closed reactors totaling 78.1 GW of capacity. Since WNISR2018, eight additional reactors (4.5 GW) have been officially closed: two each in Japan, Russia and the U.S., and one each in South Korea and Taiwan. Close to 60 percent of the closed units are located in Europe (85 in Western Europe and 23 in Central and Eastern Europe), followed by North America (42) and Asia (31). Around 78 percent or 140 reactors are using three reactor technologies: Pressurized Water Reactors or PWRs (30 percent or 54 units), Boiling Water Reactors or BWRs (27 percent or 48 units), and the Gas-Cooled Reactors or GCRs (21 percent or 38 units). Of the latter, the majority (27 reactors) are located in the U.K.

Figure 36 gives an overview of the closed reactors by country and reactor technology. The U.S. and Germany each have six different reactor types, the highest diversity among the countries with closed reactors. Spain has only three closed reactors but three different reactor types to dismantle.

Decommissioning is only at its very beginnings. Assuming a 40-year average lifetime, a further 207 reactors will close by 2030 (reactors connected to the grid between 1979 and 1990); and an additional 125 will be closed by 2059; this does not even account for the 85 reactors which started operating before 1979, an additional 28 reactors in Long-term Outage (LTO) and the 46 reactors under construction as of mid-2019.

Overview of Reactors with Completed Decommissioning

Source: WNISR and IAEA-PRIS, 2018-19

As of the first quarter of 2019, 162 units are globally awaiting or in various stages of decommissioning, eight more than in the first quarter of 2018. No reactor completed decommissioning worldwide since WNISR2018 (see Figure 37). Overall, only 19 reactors, with a capacity of 6 GW, were fully decommissioned, i.e. only 8 percent of the total 78.1 GW withdrawn from the grid. Of the 19 decommissioned reactors, only 10 have been returned to greenfield sites. The average duration of the decommissioning process, independent of the chosen strategy, is around 19 years, with a very high variance: the minimum of six years for the 22-MW Elk River plant, and the maximum of 42 years for the 17-MW CVTR (Carolinas-Virginia Tube Reactor), both in the U.S.

Elements of National Decommissioning Policies

When analyzing decommissioning policies, one needs to distinguish between the process itself (in the sense of the actual implementation), and the financing of decommissioning. The technological process can generally be divided into three main stages, which are briefly described hereunder (for more details, see WNISR2018).

• The Warm-up-stage comprises the post-operational stage, the dismantling of systems that are not needed for the decommissioning process. Also, the dismantling of higher contaminated system parts begins. An indicator for the progress of this stage is the defueling of the reactor as it is crucial for further undertakings: defueling means removing the spent fuel from the reactor core and the spent fuel pools.
• The Hot-zone-stage comprises the dismantling activities in the hot zone, i.e. dismantling of highly contaminated or activated parts, e.g. the reactor pressure vessel (RPV) and its internals (RVI), and the biological shield.
• The Ease-off-stage comprises removal of operating systems as well as decontamination of the buildings. This stage ends ideally with the demolition of the buildings and the release of the reactor site as a greenfield for unrestricted use but the release as a brownfield is allowed in some countries, which means that the buildings can also be further used, for nuclear or other purposes.

With respect to financing, four main approaches are observable: Public budget, external segregated fund, internal non-segregated fund, and internal segregated fund (for more details, see WNISR2018).

Case Studies North America, Europe, and Asia

WNISR2019 contains case studies of decommissioning in North America (U.S. and Canada), Europe, and Asia and counted 140 closed reactors in the U.S., Canada, France, Germany, Japan, and the U.K. that represent almost 79 percent of the worldwide total closed fleet. The country case-studies suggest that both duration and costs have been largely underestimated. In nearly all the cases, the few started decommissioning projects encounter delays as well as cost increases.

The U.S. have decommissioned the highest number of reactors (13), followed by Germany (5), and Japan (1). By contrast, the early nuclear states U.K., France and Canada have not fully decommissioned one single reactor. Table 11 reflects the little progress that the entire decommissioning process is making: between July 2018 and June 2019, no additional reactor was completely decommissioned, and little progress can be reported for the rest of the reactors undergoing decommissioning.

In Germany, Neckarwestheim-1 and Philippsburg-1 were defueled.629 In France, it was announced that the decommissioning of the small 80 MW Brennilis reactor will be further delayed, with the earliest possible completion in 2038. The decree formalizing that timeframe is expected to be signed by 2021.630 In Japan, Genkai-2 and Onagawa-1 have been officially closed; WNISR2018 already counted these two reactors in Longt-Term Outage (LTO). In 2019, Japan Atomic Power Company (JAPC), which owns the two Tokai and the two Tsuruga reactors—all four are either closed or in LTO—announced that it considers setting up a subsidiary for decommissioning its reactors together with EnergySolutions as operator.631 JAPC is decommissioning the GCR Tokai-1 as well as Tsuruga-1 since 2017 and supports decommissioning works for the Fukushima Daiichi plant. Already in 2016, EnergySolutions and JAPC signed a cooperation agreement and JAPC members visited the Zion site in the USA.632

In the U.S., there was no tangible progress in reactor decommissioning, but it seems that the new organizational model of selling the license to a decommissioning contractor, identified in WNISR2018, gains popularity. In December 2018, the Vermont Public Utility Commission approved the operating license transfer from Entergy to Northstar, mainly due to the accelerated decommissioning plan, Northstar would start with decommissioning no later than 2021.633 The transfer also includes the dry storage facility.634 In June 2019, Duke Energy announced that it plans to sell the operating license for Crystal River-3, which is currently in Long Time Enclosure (LTE), to the Northstar and Orano joint-venture.635 Before this deal, the model was already applied to three reactors (Zion-1, Zion-2 and Lacrosse); here the license was sold to waste-management company EnergySolutions, which seems to be involved in most if not all decommissioning projects. In early 2019, Omaha Public Power District (OPPD), owner and operator of Fort Calhoun-1, signed a contract with EnergySolutions for technical support for decommissioning the reactor, although no details about the contract, including its value, have been disclosed.636 The strategy has been changed to immediate dismantling, and OPPD estimates that decommissioning costs could be reduced by US$200 million (i.e. a total cost of around US$1.1 billion or US$2,250/kW). Contrary to other cases, EnergySolutions does not take over the license and the funds but OPPD retains full ownership, control and regulatory accountability.637 EnergySolutions estimated that it will finish decommissioning Lacrosse and the two Zion units in late 2019.638

The two units San Onofre-2 and -3 are not yet defueled but this is scheduled to be completed by the end of 2019. Underground storage vaults were installed to this end. Defueling might be delayed, however, as the Nuclear Regulatory Commission (NRC) is currently evaluating an incident at the station, where staff came close to dropping 18 feet (6 meters) a container containing 50 tons of spent fuel. One canister got stuck and was not properly inserted, which the operator Southern California Edison (SCE) first failed to note; only after radiation protection registered unusually high radiation was the problem realized and solved.639 SCE has come under pressure recently with a San Diego attorney calling for criminal investigations by the FBI640 and congressmen announcing new legislation amid serious environmental and safety concerns.641

On 17 September 2018, Oyster Creek, a 619 MW GE BWR-2 (Mark 1) reactor and the first “commercial” and then oldest reactor in the U.S., was closed after 49 years of operation, 11 years before its license expires in 2029. Exelon will now defuel the plant with plans to sell it to the newly created joint venture Comprehensive Decommissioning International consisting of Holtec International (U.S. waste management company) and SNC-Lavalin (Canadian engineering company). The company plans to acquire the decommissioning licenses of two Entergy reactors in the coming years: Pilgrim, closed on 31 May 2019 and Palisades, planned to close definitely in 2022.642

Thus, of the ten reactors undergoing decommissioning, six were sold to decommissioning companies, only four—the Humboldt Bay station and the San Onofre plant (three units)—were not. As reported in WNISR2018, there is a need for a high level of scrutiny to these models, as in most cases the decommissioning funds are also transferred to the new licensee. In the case of Oyster Creek, the latest reported decommissioning fund contained US$888.5 million as of late 2016 with a site-specific cost estimate of around US$1,083 million for decommissioning including spent fuel management.643 These developments are problematic as limited-liability companies are only financially liable—in the case of an accident or other legal dispute—up to the value of their assets. Therefore, if the decommissioning funds are exhausted, such a third-party company could declare bankruptcy, leaving the bill to the taxpayer.

Sources: compiled by WNISR, 2018, 2019

Notes

a – includes the four Fukushima Daini reactors, not included in 2018

b - corrected from WNISR2018

Case Studies: Western Europe, Central and Eastern Europe, and Asia

The following section provides an in-depth review of developments in five countries in Western Europe, Central and Eastern Europe, and Asia with 19 closed reactors (6 PWR, 3 BWR, 2 GCR, 7 LWGR and 1 PHWR) in Spain, Italy, Lithuania, Russia, and South Korea. Together with the six case studies reviewed in WNISR2018 and updated in WNSIR2019, we cover a total of 159 closed reactors, representing almost 87 percent of the worldwide closed fleet. In Spain, Italy, Lithuania, Russia, and the Republic of Korea 19 reactors are currently awaiting or are in various stages of decommissioning, while none of the observed countries has yet fully decommissioned one reactor. In Lithuania, an RBMK reactor is for the first time undergoing decommissioning.

Spain

Decommissioning Monitoring

As of mid-2019, Spain had three closed reactors with a combined capacity of 1,067 MW. The first was José Cabrera-1, a 241 MW Westinghouse Pressurized Water Reactor or PWR (1-Loop), which was closed in 2006. It was the first Spanish reactor to start and it operated for 37 years east of Madrid. Decommissioning was started after a “transition period” in 2010. Between 2013 and 2015 Westinghouse performed the segmentation (underwater mechanical cutting) and packaging of the reactor pressure vessel as well as the reactor internals.644 The vessel and some internals were transported to the Cabril Waste Repository, while some internals are still stored with the spent fuel on-site in the interim storage facility.645 The reactor is currently in the ease-off-stage and decommissioning is expected to be completed by 2020. The original budget for decommissioning including site restoration was approximately €150 million or €1,400/kW (US$169 million or US$1,600/kW).646 In 2016, the cost estimate for the project had nearly doubled to around €259 million or €1,800/kW (US$292 million or US$2,100/kW).647

The second reactor to be decommissioning is Vandellos-1, a 480 MW GCR (or UNGG for Uranium Naturel Graphite Gaz) designed and supplied by the French state agency CEA. The GCR was operational from 1972 on and closed in 1990, following an incident in which one of its turbo generators was damaged. The owner of Vandellos-1, Hifrensa, defueled the reactor, conditioned the operational wastes, and extracted the wastes from the graphite silos. After this, Enresa took over decommissioning in 1998 and removed unnecessary conventional structures. The pressure vessel was confined and covered by a protective structure. Dismantling of the vessel and remaining internals is expected to begin in 2028, after an enclosure period of 25 years.648 At the lower floor of the reactor building a temporary graphite storage facility was installed, where some 1,100 tons of graphite from the sleeves of the fuel used during operation are stored.649 In 2018, a contract between Enresa and EDF was signed covering a four-year period of engineering support for the enclosure period, the contract includes the preparation of technical and licensing documentation.650 Although some decommissioning work was done, WNISR considers the reactor as in Long Term Enclosure (LTE), as the main decommissioning work will be carried out after an enclosure period of 25 years.

The third closed reactor is the GE BWR at the Santa Maria de Garoña station, which was operational from 1971 until 2012. Iberdrola has no intentions of bringing the reactor back online, as Garona is not economically viable, and the necessary investments were described as potentially ruinous to the utility (see WNISR2018). The 446 MW BWR will now enter the decommissioning stage. The operator, Nuclenor (a joint venture of Endesa and Iberdrola), will have to defuel the reactor and transfer the spent fuel to the interim storage facility as well as condition the operational wastes. Then, Enresa will take over the ownership of the plant. Enresa estimates that decommissioning will take about ten years.651 The reactor is currently in the “warm-up-stage”. Table 12 shows the current status of reactor decommissioning in Spain.