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Nuclear Power in a Clean Energy System

About this report.

With nuclear power facing an uncertain future in many countries, the world risks a steep decline in its use in advanced economies that could result in billions of tonnes of additional carbon emissions. Some countries have opted out of nuclear power in light of concerns about safety and other issues. Many others, however, still see a role for nuclear in their energy transitions but are not doing enough to meet their goals.

The publication of the IEA's first report addressing nuclear power in nearly two decades brings this important topic back into the global energy debate.

Key findings

Nuclear power is the second-largest source of low-carbon electricity today.

Nuclear power is the second-largest source of low-carbon electricity today, with 452 operating reactors providing 2700 TWh of electricity in 2018, or 10% of global electricity supply.

In advanced economies, nuclear has long been the largest source of low-carbon electricity, providing 18% of supply in 2018. Yet nuclear is quickly losing ground. While 11.2 GW of new nuclear capacity was connected to power grids globally in 2018 – the highest total since 1990 – these additions were concentrated in China and Russia.

Global low-carbon power generation by source, 2018

Cumulative co2 emissions avoided by global nuclear power in selected countries, 1971-2018, an aging nuclear fleet.

In the absense of further lifetime extensions and new projects could result in an additional 4 billion tonnes of CO2 emissions, underlining the importance of the nuclear fleet to low-carbon energy transitions around the globe. In emerging and developing economies, particularly China, the nuclear fleet will provide low-carbon electricity for decades to come.

However the nuclear fleet in advanced economies is 35 years old on average and many plants are nearing the end of their designed lifetimes. Given their age, plants are beginning to close, with 25% of existing nuclear capacity in advanced economies expected to be shut down by 2025.

It is considerably cheaper to extend the life of a reactor than build a new plant, and costs of extensions are competitive with other clean energy options, including new solar PV and wind projects. Nevertheless they still represent a substantial capital investment. The estimated cost of extending the operational life of 1 GW of nuclear capacity for at least 10 years ranges from $500 million to just over $1 billion depending on the condition of the site.

However difficult market conditions are a barrier to lifetime extension investments. An extended period of low wholesale electricity prices in most advanced economies has sharply reduced or eliminated margins for many technologies, putting nuclear at risk of shutting down early if additional investments are needed. As such, the feasibility of extensions depends largely on domestic market conditions.

Age profile of nuclear power capacity in selected regions, 2019

United states, levelised cost of electricity in the united states, 2040, european union, levelised cost of electricity in the european union, 2040, levelised cost of electricity in japan, 2040, the nuclear fade case, nuclear capacity operating in selected advanced economies in the nuclear fade case, 2018-2040, wind and solar pv generation by scenario 2019-2040, policy recommendations.

In this context, countries that intend to retain the option of nuclear power should consider the following actions:

• Keep the option open:  Authorise lifetime extensions of existing nuclear plants for as long as safely possible. 
• Value dispatchability:  Design the electricity market in a way that properly values the system services needed to maintain electricity security, including capacity availability and frequency control services. Make sure that the providers of these services, including nuclear power plants, are compensated in a competitive and non-discriminatory manner.
• Value non-market benefits:  Establish a level playing field for nuclear power with other low-carbon energy sources in recognition of its environmental and energy security benefits and remunerate it accordingly.
• Update safety regulations:  Where necessary, update safety regulations in order to ensure the continued safe operation of nuclear plants. Where technically possible, this should include allowing flexible operation of nuclear power plants to supply ancillary services.
• Create a favourable financing framework:  Create risk management and financing frameworks that facilitate the mobilisation of capital for new and existing plants at an acceptable cost taking the risk profile and long time-horizons of nuclear projects into consideration.
• Support new construction:  Ensure that licensing processes do not lead to project delays and cost increases that are not justified by safety requirements.
• Support innovative new reactor designs:  Accelerate innovation in new reactor designs with lower capital costs and shorter lead times and technologies that improve the operating flexibility of nuclear power plants to facilitate the integration of growing wind and solar capacity into the electricity system.
• Maintain human capital:  Protect and develop the human capital and project management capabilities in nuclear engineering.

Executive summary

Nuclear power can play an important role in clean energy transitions.

Nuclear power today makes a significant contribution to electricity generation, providing 10% of global electricity supply in 2018.  In advanced economies 1 , nuclear power accounts for 18% of generation and is the largest low-carbon source of electricity. However, its share of global electricity supply has been declining in recent years. That has been driven by advanced economies, where nuclear fleets are ageing, additions of new capacity have dwindled to a trickle, and some plants built in the 1970s and 1980s have been retired. This has slowed the transition towards a clean electricity system. Despite the impressive growth of solar and wind power, the overall share of clean energy sources in total electricity supply in 2018, at 36%, was the same as it was 20 years earlier because of the decline in nuclear. Halting that slide will be vital to stepping up the pace of the decarbonisation of electricity supply.

A range of technologies, including nuclear power, will be needed for clean energy transitions around the world.  Global energy is increasingly based around electricity. That means the key to making energy systems clean is to turn the electricity sector from the largest producer of CO 2 emissions into a low-carbon source that reduces fossil fuel emissions in areas like transport, heating and industry. While renewables are expected to continue to lead, nuclear power can also play an important part along with fossil fuels using carbon capture, utilisation and storage. Countries envisaging a future role for nuclear account for the bulk of global energy demand and CO 2 emissions. But to achieve a trajectory consistent with sustainability targets – including international climate goals – the expansion of clean electricity would need to be three times faster than at present. It would require 85% of global electricity to come from clean sources by 2040, compared with just 36% today. Along with massive investments in efficiency and renewables, the trajectory would need an 80% increase in global nuclear power production by 2040.

Nuclear power plants contribute to electricity security in multiple ways.  Nuclear plants help to keep power grids stable. To a certain extent, they can adjust their operations to follow demand and supply shifts. As the share of variable renewables like wind and solar photovoltaics (PV) rises, the need for such services will increase. Nuclear plants can help to limit the impacts from seasonal fluctuations in output from renewables and bolster energy security by reducing dependence on imported fuels.

Lifetime extensions of nuclear power plants are crucial to getting the energy transition back on track

Policy and regulatory decisions remain critical to the fate of ageing reactors in advanced economies.  The average age of their nuclear fleets is 35 years. The European Union and the United States have the largest active nuclear fleets (over 100 gigawatts each), and they are also among the oldest: the average reactor is 35 years old in the European Union and 39 years old in the United States. The original design lifetime for operations was 40 years in most cases. Around one quarter of the current nuclear capacity in advanced economies is set to be shut down by 2025 – mainly because of policies to reduce nuclear’s role. The fate of the remaining capacity depends on decisions about lifetime extensions in the coming years. In the United States, for example, some 90 reactors have 60-year operating licenses, yet several have already been retired early and many more are at risk. In Europe, Japan and other advanced economies, extensions of plants’ lifetimes also face uncertain prospects.

Economic factors are also at play.  Lifetime extensions are considerably cheaper than new construction and are generally cost-competitive with other electricity generation technologies, including new wind and solar projects. However, they still need significant investment to replace and refurbish key components that enable plants to continue operating safely. Low wholesale electricity and carbon prices, together with new regulations on the use of water for cooling reactors, are making some plants in the United States financially unviable. In addition, markets and regulatory systems often penalise nuclear power by not pricing in its value as a clean energy source and its contribution to electricity security. As a result, most nuclear power plants in advanced economies are at risk of closing prematurely.

The hurdles to investment in new nuclear projects in advanced economies are daunting

What happens with plans to build new nuclear plants will significantly affect the chances of achieving clean energy transitions.  Preventing premature decommissioning and enabling longer extensions would reduce the need to ramp up renewables. But without new construction, nuclear power can only provide temporary support for the shift to cleaner energy systems. The biggest barrier to new nuclear construction is mobilising investment.  Plans to build new nuclear plants face concerns about competitiveness with other power generation technologies and the very large size of nuclear projects that require billions of dollars in upfront investment. Those doubts are especially strong in countries that have introduced competitive wholesale markets.

A number of challenges specific to the nature of nuclear power technology may prevent investment from going ahead.  The main obstacles relate to the sheer scale of investment and long lead times; the risk of construction problems, delays and cost overruns; and the possibility of future changes in policy or the electricity system itself. There have been long delays in completing advanced reactors that are still being built in Finland, France and the United States. They have turned out to cost far more than originally expected and dampened investor interest in new projects. For example, Korea has a much better record of completing construction of new projects on time and on budget, although the country plans to reduce its reliance on nuclear power.

Without nuclear investment, achieving a sustainable energy system will be much harder

A collapse in investment in existing and new nuclear plants in advanced economies would have implications for emissions, costs and energy security.  In the case where no further investments are made in advanced economies to extend the operating lifetime of existing nuclear power plants or to develop new projects, nuclear power capacity in those countries would decline by around two-thirds by 2040. Under the current policy ambitions of governments, while renewable investment would continue to grow, gas and, to a lesser extent, coal would play significant roles in replacing nuclear. This would further increase the importance of gas for countries’ electricity security. Cumulative CO 2 emissions would rise by 4 billion tonnes by 2040, adding to the already considerable difficulties of reaching emissions targets. Investment needs would increase by almost USD 340 billion as new power generation capacity and supporting grid infrastructure is built to offset retiring nuclear plants.

Achieving the clean energy transition with less nuclear power is possible but would require an extraordinary effort.  Policy makers and regulators would have to find ways to create the conditions to spur the necessary investment in other clean energy technologies. Advanced economies would face a sizeable shortfall of low-carbon electricity. Wind and solar PV would be the main sources called upon to replace nuclear, and their pace of growth would need to accelerate at an unprecedented rate. Over the past 20 years, wind and solar PV capacity has increased by about 580 GW in advanced economies. But in the next 20 years, nearly five times that much would need to be built to offset nuclear’s decline. For wind and solar PV to achieve that growth, various non-market barriers would need to be overcome such as public and social acceptance of the projects themselves and the associated expansion in network infrastructure. Nuclear power, meanwhile, can contribute to easing the technical difficulties of integrating renewables and lowering the cost of transforming the electricity system.

With nuclear power fading away, electricity systems become less flexible.  Options to offset this include new gas-fired power plants, increased storage (such as pumped storage, batteries or chemical technologies like hydrogen) and demand-side actions (in which consumers are encouraged to shift or lower their consumption in real time in response to price signals). Increasing interconnection with neighbouring systems would also provide additional flexibility, but its effectiveness diminishes when all systems in a region have very high shares of wind and solar PV.

Offsetting less nuclear power with more renewables would cost more

Taking nuclear out of the equation results in higher electricity prices for consumers.  A sharp decline in nuclear in advanced economies would mean a substantial increase in investment needs for other forms of power generation and the electricity network. Around USD 1.6 trillion in additional investment would be required in the electricity sector in advanced economies from 2018 to 2040. Despite recent declines in wind and solar costs, adding new renewable capacity requires considerably more capital investment than extending the lifetimes of existing nuclear reactors. The need to extend the transmission grid to connect new plants and upgrade existing lines to handle the extra power output also increases costs. The additional investment required in advanced economies would not be offset by savings in operational costs, as fuel costs for nuclear power are low, and operation and maintenance make up a minor portion of total electricity supply costs. Without widespread lifetime extensions or new projects, electricity supply costs would be close to USD 80 billion higher per year on average for advanced economies as a whole.

Strong policy support is needed to secure investment in existing and new nuclear plants

Countries that have kept the option of using nuclear power need to reform their policies to ensure competition on a level playing field.  They also need to address barriers to investment in lifetime extensions and new capacity. The focus should be on designing electricity markets in a way that values the clean energy and energy security attributes of low-carbon technologies, including nuclear power.

Securing investment in new nuclear plants would require more intrusive policy intervention given the very high cost of projects and unfavourable recent experiences in some countries.  Investment policies need to overcome financing barriers through a combination of long-term contracts, price guarantees and direct state investment.

Interest is rising in advanced nuclear technologies that suit private investment such as small modular reactors (SMRs).  This technology is still at the development stage. There is a case for governments to promote it through funding for research and development, public-private partnerships for venture capital and early deployment grants. Standardisation of reactor designs would be crucial to benefit from economies of scale in the manufacturing of SMRs.

Continued activity in the operation and development of nuclear technology is required to maintain skills and expertise.  The relatively slow pace of nuclear deployment in advanced economies in recent years means there is a risk of losing human capital and technical know-how. Maintaining human skills and industrial expertise should be a priority for countries that aim to continue relying on nuclear power.

The following recommendations are directed at countries that intend to retain the option of nuclear power. The IEA makes no recommendations to countries that have chosen not to use nuclear power in their clean energy transition and respects their choice to do so.

• Keep the option open:  Authorise lifetime extensions of existing nuclear plants for as long as safely possible.
• Value non-market benefits:  Establish a level playing field for nuclear power with other low carbon energy sources in recognition of its environmental and energy security benefits and remunerate it accordingly.
• Create an attractive financing framework:  Set up risk management and financing frameworks that can help mobilise capital for new and existing plants at an acceptable cost, taking the risk profile and long time horizons of nuclear projects into consideration.
• Support new construction:  Ensure that licensing processes do not lead to project delays and cost increases that are not justified by safety requirements. Support standardisation and enable learning-by-doing across the industry.
• Support innovative new reactor designs:  Accelerate innovation in new reactor designs, such as small modular reactors (SMRs), with lower capital costs and shorter lead times and technologies that improve the operating flexibility of nuclear power plants to facilitate the integration of growing wind and solar capacity into the electricity system.

Advanced economies consist of Australia, Canada, Chile, the 28 members of the European Union, Iceland, Israel, Japan, Korea, Mexico, New Zealand, Norway, Switzerland, Turkey and the United States.

Reference 1

Cite report.

IEA (2019), Nuclear Power in a Clean Energy System , IEA, Paris https://www.iea.org/reports/nuclear-power-in-a-clean-energy-system, Licence: CC BY 4.0

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Building nuclear power plants

Why do costs exceed projections.

An MIT team has revealed why, in the field of nuclear power, experience with a given technology doesn’t always lower costs. When it comes to building a nuclear power plant in the United States—even of a well-known design—the total bill is often three times as high as expected. Using a new analytical approach, the researchers delved into the cost overrun from non-hardware-related activities such as engineering services and labor supervision. Tightening safety regulations were responsible for some of the cost increase, but declining labor productivity also played a significant role. Analyses of possible cost-reduction strategies show potential gains from technology development to reduce materials use and to automate some construction tasks. Cost overruns continue to be left out of nuclear industry projections and overlooked in the design process in the United States, but the researchers’ approach could help solve those problems. Their new tool should prove valuable to design engineers, developers, and investors in any field with demanding and changeable regulatory and site-specific requirements.

Nuclear power is frequently cited as a critical component in the portfolio of technologies aimed at reducing greenhouse gas emissions. But rising construction costs and project delays have hampered efforts to expand nuclear capacity in the United States since the 1970s. At plants begun after 1970, the average cost of construction has typically been far higher than the initial cost estimate.

Nevertheless, the nuclear industry, government, and research agencies continue to forecast cost reductions in nuclear plant construction. A key assumption in such projections is that costs will decline as the industry gains experience with a given reactor design. “It’s often included in models, with huge impacts on the outcomes of projected energy supply mixes,” says Jessika E. Trancik , an associate professor of energy studies in the MIT Institute for Data, Systems, and Society (IDSS).

That expectation is based on an assumption typically expressed in terms of the “learning rate” for a given technology, which represents the percent cost reduction associated with a doubling of cumulative production. Nuclear industry cost-estimating guidelines as well as widely used climate models and global energy scenarios often rely on learning rates that significantly reduce costs as installed nuclear capacity increases. Yet empirical evidence shows that in the case of nuclear plants, learning rates are negative. Costs just keep rising.

To investigate, Trancik and her team—co-first authors Philip Eash-Gates SM ’19 and IDSS postdoc Magdalena M. Klemun PhD ’19; IDSS postdoc Gökşin Kavlak; former IDSS research scientist James McNerney; and TEPCO Professor of Nuclear Science and Engineering Jacopo Buongiorno —began by looking at industry data on the cost of construction (excluding financing costs) over five decades from 107 nuclear plants across the United States. They estimated a negative learning rate consistent with a doubling of construction costs with each doubling of cumulative U.S. capacity.

That result is based on average costs across nuclear plants of all types. One explanation is that the rise in average costs hides trends of decreasing costs in particular reactor designs. So the researchers examined the cost trajectories of four standard plant designs installed in the United States that reached a cumulative built capacity of 8 gigawatts-electric. Their results appear below. They found that construction costs for each of the four designs rose as more plants were built. In fact, the first one built was the least expensive in three of the four cases and was among the least expensive plants in the fourth.

“We’ve confirmed that costs have risen even for plants of the same design class,” says Trancik. “That outcome defies engineering expectations.” She notes that a common view is that more stringent safety regulations have increased the cost of nuclear power plant construction. But is that the full explanation, or are other factors at work as well?

Source of increasing cost

To find out, the researchers examined cost data from 1976 to 1987 in the U.S. Department of Energy’s Energy Economic Data Base. (After 1987 the DOE database was no longer updated.) They looked at the contributions to overall cost increases of 61 “cost accounts” representing individual plant components and the services needed to install them.

They found that the overall trend was an increase in costs. Many accounts contribute to the total cost escalation, so the researchers couldn’t easily identify one source. But they could group the accounts into two categories: direct costs and indirect costs. Direct costs are costs of materials and labor needed for physical components such as reactor equipment and control and monitoring systems. Indirect costs are construction support activities such as engineering, administration, and construction supervision. The figure below shows their results.

The researchers concluded that between 1976 and 1987, indirect costs—those external to hardware—caused 72% of the cost increase. “Most aren’t hardware-related but rather are what we call soft costs,” says Trancik. “Examples include rising expenditures on engineering services, on-site job supervision, and temporary construction facilities.”

To determine which aspects of the technology were most responsible for the rise in indirect expenses, they delved further into the DOE dataset and attributed the indirect expenses to the specific plant components that incurred them. The analysis revealed that three components were most influential in causing the indirect cost change: the nuclear steam supply system, the turbine generator, and the containment building. All three also contributed heavily to the direct cost increase.

A case study

For further insight, the researchers undertook a case study focusing on the containment building. This airtight, steel-and-concrete structure forms the outermost layer of a nuclear reactor and is designed to prevent the escape of radioactive materials as well as to protect the plant from aircraft impact, missile attack, and other threats. As such, it is one of the most expensive components and one with significant safety requirements.

Based on historical and recent design drawings, the researchers extended their analysis from the 1976–1987 period to the year 2017. Data on indirect costs aren’t available for 2017, so they focused on the direct cost of the containment building. Their goal was to break down cost changes into underlying engineering choices and productivity trends.

They began by developing a standard cost equation that could calculate the cost of the containment building based on a set of underlying variables—from wall thickness to laborer wages to the prices of materials. To track the effects of labor productivity trends on cost, they included variables representing steel and concrete “deployment rates,” defined as the ratio of material volumes to the amount of labor (in person-hours) required to deploy them during construction.

A cost equation can be used to calculate how a change in one variable will affect overall cost. But when multiple variables are changing at the same time, adding up the individual impacts won’t work because they interact. Trancik and her team therefore turned to a novel methodology they developed in 2018 to examine what caused the cost of solar photovoltaic modules to drop so much in recent decades. Based on their cost equation for the containment building and following their 2018 methodology, they derived a “cost change equation” that can quantify how a change in each variable contributes to the change in overall cost when the variables are all changing at once.

Their results, summarized in the right-hand panel of the figure below, show that the major contributors to the rising cost of the containment building between 1976 and 2017 were changes in the thickness of the structure and in the materials deployment rates. Changes to other plant geometries and to prices of materials brought costs down but not enough to offset those increases.

Percentage contribution of variables to increases in containment building costs These panels summarize types of variables that caused costs to increase between 1976 and 2017. In the first time period (left panel), the major contributor was a drop in the rate at which materials were deployed during construction. In the second period (middle panel), the containment building was redesigned for improved safety during possible emergencies, and the required increase in wall thickness pushed up costs. Overall, from 1976 to 2017 (right panel), the cost of a containment building more than doubled.

As the left and center panels above show, the importance of those mechanisms changed over time. Between 1976 and 1987, the cost increase was caused primarily by declining deployment rates; in other words, productivity dropped. Between 1987 and 2017, the containment building was redesigned for passive cooling, reducing the need for operator intervention during emergencies. The new design required that the steel shell be approximately five times thicker in 2017 than it had been in 1987—a change that caused 80% of the cost increase over the 1976–2017 period.

Overall, the researchers found that the cost of the reactor containment building more than doubled between 1976 and 2017. Most of that cost increase was due to increasing materials use and declining on-site labor productivity—not all of which could be clearly attributed to safety regulations. Labor productivity has been declining in the construction industry at large, but at nuclear plants it has dropped far more rapidly. “Material deployment rates at recent U.S. ‘new builds’ have been up to 13 times lower than those assumed by the industry for cost estimation purposes,” says Trancik. “That disparity between projections and actual experience has contributed significantly to cost overruns.”

Discussion so far has focused on what the researchers call “low-level mechanisms” of cost change—that is, cost change that arises from changes in the variables in their cost model, such as materials deployment rates and containment wall thickness. In many cases, those changes have been driven by “high-level mechanisms” such as human activities, strategies, regulations, and economies of scale.

The researchers identified four high-level mechanisms that could have driven the low-level changes. The first three are “R&D,” which can lead to requirements for significant modifications to the containment building design and construction process; “process interference, safety,” which includes the impacts of on-site safety-related personnel on the construction process; and “worsening despite doing,” which refers to decreases in the performance of construction workers, possibly due to falling morale and other changes. The fourth mechanism— “other”—includes changes that originate outside the nuclear industry, such as wage or commodity price changes. Following their 2018 methodology, the team assigned each low-level cost increase to the high-level mechanism or set of mechanisms that caused it.

The analysis showed that R&D-related activities contributed roughly 30% to cost increases, and on-site procedural changes contributed roughly 70%. Safety-related mechanisms caused about half of the direct cost increase over the 1976 to 2017 period. If all the productivity decline were attributed to safety, then 90% of the overall cost increase could be linked to safety. But historical evidence points to the existence of construction management and worker morale issues that cannot be clearly linked to safety requirements.

Lessons for the future

The researchers next used their models in a prospective study of approaches that might help to reduce nuclear plant construction costs in the future. In particular, they examined whether the variables representing the low-level mechanisms at work in the past could be addressed through innovation. They looked at three scenarios, each of which assumes a set of changes to the variables in the cost model relative to their values in 2017.

In the first scenario, they assume that cost improvement occurs broadly. Specifically, all variables change by 20% in a cost-reducing direction. While they note that such across-the-board changes are meant to represent a hypothetical and not a realistic scenario, the analysis shows that reductions in the use of rebar (the steel bars in reinforced concrete) and in steelworker wages are most influential, together causing 40% of the overall reduction in direct costs.

In the second scenario, they assume that on-site productivity increases due to the adoption of advanced manufacturing and construction management techniques. Scenario 2 reduces costs by 34% relative to estimated 2017 costs, primarily due to increased automation and improved management of construction activities, including automated concrete deployment and optimized rebar delivery. However, costs are still 30% above 1976 costs.

The third scenario focuses on advanced construction materials such as high-strength steel and ultra-high-performance concrete, which have been shown to reduce commodity use and improve on-site workflows. This scenario reduces cost by only 37% relative to 2017 levels, in part due to the high cost of the materials involved. And the cost is still higher than it was in 1976.

Decreases in containment building costs due to four high-level mechanisms under three innovation strategies Scenario 1 assumes a 20% improvement in all variables; Scenario 2 increases on-site material deployment rates by using advanced manufacturing and construction management techniques; and Scenario 3 involves use of advanced, high-strength construction materials. All three strategies would require significant R&D investment, but the importance of the other high-level mechanisms varies. For example, “learning-by-doing” is important in Scenario 2 because assumed improvements such as increased automation will require some on-site optimization of robot operation. In Scenario 3, the use of advanced materials is assumed to require changes in building design and workflows, but those changes can be planned off-site, so are assigned to R&D and “knowledge spillovers.”

To figure out the high-level mechanisms that influenced those outcomes, the researchers again assigned the low-level mechanisms to high-level mechanisms, in this case including “learning-by-doing” as well as “knowledge spillovers,” which accounts for the transfer of external innovations to the nuclear industry. As shown above, the importance of the mechanisms varies from scenario to scenario. But in all three, R&D would have to play a far more significant role in affecting costs than it has in the past.

Analysis of the scenarios suggests that technology development to reduce commodity usage and to automate construction could significantly reduce costs and increase resilience to changes in regulatory requirements and on-site conditions. But the results also demonstrate the challenges in any effort to reduce nuclear plant construction costs. The cost of materials is highly influential, yet it is one of the variables most constrained by safety standards, and—in general—materials-related cost reductions are limited by the large-scale dimensions and labor intensity of nuclear structures.

Nevertheless, there are reasons to be encouraged by the results of the analyses. They help explain the constant cost overruns in nuclear construction projects and also demonstrate new tools that engineers can use to predict how design changes will affect both hardware- and non-hardware-related costs in this and other technologies. In addition, the work has produced new insights into the process of technology development and innovation. “Using our approach, researchers can explore scenarios and new concepts, such as microreactors and small modular reactors,” says Trancik. “And it may help in the engineering design of other technologies with demanding and changeable on-site construction and performance requirements.” Finally, the new technique can help guide R&D investment to target areas that can deliver real-world cost reductions and further the development and deployment of various technologies, including nuclear power and others that can help in the transition to a low-carbon energy future.

This research was supported by the David and Lucile Packard Foundation and the MIT Energy Initiative. Philip Eash-Gates SM ’19 is now a senior associate at Synapse Energy Economics. James McNerney is a research associate in the Center for International Development at Harvard University. Further information about this research and the earlier study of photovoltaic technology can be found in:

P. Eash-Gates, M.M. Klemun, G. Kavlak, J. McNerney, J. Buongiorno, and J.E. Trancik. “Sources of cost overrun in nuclear power plant construction call for a new approach to engineering design.” Joule , November 2020. Online: doi.org/10.1016/j.joule.2020.10.001

G. Kavlak, J. McNerney, J.E. Trancik. “Evaluating the causes of cost reduction in photovoltaic modules.” Energy Policy , vol. 123, pp. 700–710, 2018. Online: doi.org/10.1016/j.enpol.2018.08.015

This article appears in the Autumn 2020 issue of Energy Futures .

Press inquiries: [email protected]

Plant Vogtle Reactors 3 and 4: A Case Study in Challenges for US Nuclear Construction

Cameron van de graaf march 21, 2017, submitted as coursework for ph241 , stanford university, winter 2017, plant origins and expansion planning, cost overruns, regulatory hurdles, and public opposition.

At the end of the day, many of the problems experienced in the construction at Vogtle are due to a vicious cycle; namely, that since few nuclear plants have been built recently in the US, everything from manufacturing to supply chains to regulation has to be done on an ad-hoc basis. Without the economies of scale from frequent construction of these sorts of projects, contractors like Westinghouse must bear the high fixed costs of getting spun up in addition to more insidious costs, like a lack of trained personnel and institutional knowledge atrophy. On the regulatory side, the NRC and state authorities err on the side of caution as few in these agencies have been around for new nuclear plant construction. Unfortunately, until such a time as the economic incentives (both market-based and subsidy-driven) align more favorably for nuclear power, it seems unlikely that the industry will break out of this cycle.

© Cameron Van de Graaf. The author grants permission to copy, distribute and display this work in unaltered form, with attribution to the author, for noncommercial purposes only. All other rights, including commercial rights, are reserved to the author.

[1] S. Lam, " Plant Vogtle: The Beginning of a Nuclear Renaissance? ,"Physics 241, Stanford University, Winter 2012.

[2] D. Biello, " Nuclear Reactor Approved in U.S. for First Time Since 1978 ," Scientific American, 9 Feb 2012.

[3] P. Barrett, " What Killed America's Climate-Saving Nuclear Renaissance? ," Bloomberg Businessweek, 27 Oct. 2015.

[4] E. Crooks and K. Inagaki, " Toshiba Brought To Its Knees By Two US Nuclear Plants ," Financial Times, 16 Feb. 2017.

[5] " Vogtle Nuclear Plant Expansion: Big Risks and Even Bigger Costs for Georgia's Residents ," Union of Concerned Scientists, January 2012.

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Social and environmental impact of nuclear power plant: A case study of Kaiga generating station in Karwar, Karnataka, India

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Suresh D. Mane , Rahul Shanbag , Pramod Madival; Social and environmental impact of nuclear power plant: A case study of Kaiga generating station in Karwar, Karnataka, India. AIP Conf. Proc. 27 November 2018; 2039 (1): 020053. https://doi.org/10.1063/1.5079012

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India has vast reserves of uranium which is a nuclear fuel. The population of nation has reached 1.3 billion and yet 71 years post independence many a villages are not connected to the electrical grid. Power quality is a perennial issue and India faces energy shortage to meet the base load as well as peak load demand. Considering the vast strides made by India in harnessing renewable energy sources like wind and solar the only green option left to exploit is that of nuclear energy. Globally as on April 2017, 30 nations are producing electricity through nuclear route employing 449 reactors which amount to 11% of electricity produced coming from nuclear power. Even 70 years after independence the nuclear energy share is less than 5 % in India and hence scope exists for enhancing its share. The nation has few scattered nuclear power plants and one of them is at Kaiga in Uttar Kannada district of Karnataka. Kaiga is located at 14.8661° N longitude and 74.4394° E latitude. This Nuclear Power Corporation of India unit was established in 2000 with two units of 220 MW capacity and expanded to four units by adding two more units of 220 MW each in 2007 and 2011. All four units are small CANDU units using natural uranium as fuel and heavy water as moderator. The unit basically is a pressurized heavy water reactor plant. The plant is successfully operating for the past 17 years without any major issues with a plant load factor exceeding 90%. This study entails designing a questionnaire and administering the same to 510 individuals covering 5% of the total population of 10 villages in 30 km radius of the plant. The results do not reveal any adverse effect of the 17 years operation of the plant on the flora and fauna of the region. The villagers and their families stand to be benefitted by the CSR activities of NPCIL over these years in the field of education, infrastructure, healthcare and transportation.

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The case for nuclear power – despite the risks

Professor of Nuclear Engineering and Radiological Sciences, University of Michigan

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Gary Was does not work for, consult, own shares in or receive funding from any company or organisation that would benefit from this article, and has disclosed no relevant affiliations beyond their academic appointment.

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This article is part of The Conversation’s worldwide series on the Future of Nuclear. You can read the rest of the series here , and a counterpoint to the views expressed in this article here .

Nuclear power is likely the least well-understood energy source in the United States. Just 99 nuclear power plants spread over 30 states provide one-fifth of America’s electricity. These plants have provided reliable, affordable and clean energy for decades. They also carry risk - to the public, to the environment and to the financial solvency of utilities.

Risk is the product of the probability of an occurrence and its consequence. The probability of dying in a car accident is actually quite high compared to other daily events, but such accidents usually claim few individuals at a time, and so the risk is low. The reason nuclear energy attracts so much attention is that while the probability of a catastrophic event is extremely low, the consequence is often perceived to be extremely high.

Nuclear power and public risk

In the US, commercial nuclear plants have been operating since the late 1960s. If you add up the plants’ years in operation, they average about 30 years each, totaling about 3,000 reactor years of operating experience. There have been no fatalities to any member of the public due to the operation of a commercial nuclear power plant in the US. Our risk in human terms is vanishingly low.

Nuclear power’s safety record is laudable, considering that nuclear plants are running full-tilt. The average capacity factor of these plants exceeds 90%; that means 99 plants are generating full power over 90% of the time.

If you compare that to any other energy form, there’s a huge gap. Coal is a mainstay of electricity generation in this country and has a capacity factor of around 65%. Gas is about the same; wind’s capacity factor is around is 30%, and solar is at 25%.

While the probability of a nuclear catastrophe is extremely low, it is only part of the risk calculation. The other part of risk is consequence. The world has been host to three major nuclear power generation accidents: Three Mile Island in 1979, Chernobyl in 1986 and Fukushima in 2011. To the best of our knowledge , Three Mile Island, while terribly frightening, resulted in no health consequences to the public.

Chernobyl was an unmitigated disaster in which the reactor vessel – the place where the nuclear fuel produces heat – was ruptured and the graphite moderator in the reactor ignited, causing an open-air fire and large releases of radioactive material. This reactor design would never have been licensed to operate in the Western world because it lacked a containment.

The scientific consensus on the effects of the disaster as developed by the United Nations Scientific Committee on the Effects of Atomic Radiation (UNSCEAR) has identified 66 deaths from trauma, acute radiation poisoning and cases of thyroid cancer . Additional deaths may occur over time, as understanding the causes of death is a statistical rather than a deterministic process. Considering that the authorities didn’t alert the neighboring communities for many hours, the long-term health consequences of that reactor accident are surprisingly small.

And then there was Fukushima Daiichi. At least three of the reactors have sustained core damage, and there is potentially damage to the reactor vessel as well. At this time, no deaths have been attributed to radiation release at Fukushima, but an estimated 1,600 people died as a result of evacuation, and land contamination was widespread.

So if you look at these cases together, in Chernobyl, you had a reactor core on fire and open to the air; in Fukushima, three reactors lost all power during full operation and sustained major core damage, resulting in substantial radioactivity release in one of the most densely populated countries in the world.

These accidents had serious, lasting consequences that aren’t to be trivialized, but the consequences are nothing like what has been feared and glorified in movies over the past 50 years. What we’ve learned about public risk during that time is that the forecasted nightmares resulting from nuclear accidents, even in serious accidents, simply haven’t come to fruition. At the same time, as a society, we’ve come to accept - or at least look the other way from - thousands of traffic- or coal-related deaths every year in the US alone.

Waste containment: risk and storage

The production of energy in any form alters the environment. Coal and natural gas generate particulates, greenhouse gases and the like. In 2012, coal plants in the US generated 110 million tons of coal ash . Nuclear waste created by power generation is in solid form, and the volume is minuscule in comparison, but extremely toxic. Even the production of wind and solar energy generates waste.

Fuel for nuclear plants is in the form of fuel assemblies or bundles, each containing tubes of a zirconium alloy that hold hundreds of ceramic pellets of uranium oxide.

Each fuel assembly provides power for four to five years before it is removed. After removal, the fuel is considered to be waste and must be safely stored, as its radiotoxicity level is extremely high. Unprocessed, it takes about 300,000 years for the radiation level of the waste inside an assembly to return to background levels, at which point it is benign.

Due to the cancellation of the Yucca Mountain site in Nevada, there is no place designated for long-term nuclear waste storage in the US, and utilities have resorted to constructing on-site storage at their plants. These storage containers were not designed to be permanent, and the Nuclear Regulatory Commission (NRC) is now licensing these temporary facilities for up to 100 years.

Many cheered when the Yucca Mountain project was shuttered , but waste still must be stored, and clearly it is safer to store the waste in a single, permanent depository than in 99 separate and temporary structures.

Monitored, retrievable storage is the safest approach to nuclear waste storage. Waste sites could be centralized and continuously monitored, and built in such a way that waste canisters could be retrieved if, for example, storage technology improves, or if it becomes economical to reprocess the waste to recover the remaining uranium and plutonium created during operation.

If we are to keep using nuclear power even at the present rate, our risks related to waste will increase every year until storage is addressed thoughtfully and thoroughly.

Infrastructure: same plant, different century

At the dawn of commercial nuclear power, the prospect of cheap, plentiful energy produced forecasts that nuclear energy would be too cheap to meter - we’d all be ripping the meters off our houses. But as plant designs evolved, it became clear that ensuring safety would increase the cost of the energy produced.

Every accident taught us something, and with every accident the NRC unveiled a new set of regulations, resulting in a system of plants that are, from the perspective of a few decades ago, much safer. Such tight regulatory oversight, while needed, drives up cost and means that utilities undertake significant financial risk with each nuclear plant they build.

Decades ago, the idea that the NRC would be granting 20-year license extensions to power plants was unheard of. Today, 75% of plants have received them. Now there’s talk about a second round of license extensions, and the NRC, the US Department of Energy and the industry are engaged in talking about what it would take to get a third. We’re talking about 80 or even 100 years of operation, in which case a plant would outlive the Earth’s population at the time it was built.

In the shorter term, life extension makes sense. Most of the plants in the United States are Generation 2 plants, but Generation 3 is being built all over the world. Gen 2 plants are proving very robust, and existing plants are quite economical to operate. Gen 3 plants, like Vogtle now being built in Georgia, boast better safety systems, better structural components and better design.

Would I rather have one of those than the one I have now? Absolutely. The risk of operating such a facility is simply lower. At US$4.5 billion to $10 billion , Gen 3 plants are very expensive to build, but we must either accept that capital outlay or find another source of electricity that has all the benefits of nuclear energy.

How much risk do we accept?

As a society, we accepted over 32,000 traffic accident deaths in 2013, and no one stopped driving as a result.

I think most people would be surprised to know that in 2012, seven million people globally died from health complications due to air pollution and that an estimated 13,000 US deaths were directly attributable to fossil-fired plants.

US deaths from coal represent an annual catastrophe that exceeds that of all nuclear accidents over all time. In fact, nuclear power has prevented an estimated 1.84 million air-pollution related deaths worldwide. Natural gas plants, increasingly being constructed around the country, are highly subject to price volatility and, while cleaner than coal, they still account for 22% of carbon dioxide emissions from electricity generation in the US. This is not to mention the illogical use of this precious resource for electricity generation versus uses for which it is more uniquely suited, such as heating homes or powering vehicles.

And until the capacity factor for renewables increases dramatically, the cost drops and large-scale storage is developed, they are simply not equipped to handle the bulk of US energy needs nor to provide electricity on demand.

Through the NRC’s oversight and the work of researchers all over the world, we have applied lessons from every global nuclear event to every American nuclear plant. The risk inherent in nuclear plant operation will always be present, but it is one of the world’s most rigorously monitored activities, and its proven performance in delivering zero-carbon electricity is one that shouldn’t be dismissed out of fear.

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Life cycle assessment of an upcoming nuclear power plant decommissioning: the Fessenheim case study from public data

• LCA FOR ENERGY SYSTEMS AND FOOD PRODUCTS
• Published: 23 April 2024

Cite this article

• Mehdi Iguider   ORCID: orcid.org/0009-0005-7137-4020 1 ,
• Paul Robineau   ORCID: orcid.org/0000-0002-2198-3689 1 ,
• Michal Kozderka   ORCID: orcid.org/0000-0001-8957-2248 2 ,
• Maria Boltoeva   ORCID: orcid.org/0000-0002-0330-8153 1 &
• Gaetana Quaranta   ORCID: orcid.org/0000-0003-4867-0030 1  

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Historical French fleet of Nuclear Power Plants (NPP) is near end-of-life, with 14 NPPs planned to begin decommissioning by 2035. Despite decade-old calls for more research regarding these activities’ environmental impact, very few if any studies were conducted since. Due to the French fleet high-degree of standardization, a prospective investigation regarding the Fessenheim NPP—first large-scale plant to be decommissioned in France, starting 2026—is conducted to identify results of interest beyond this case study.

A life cycle assessment is realized, following ISO 14040/44, with a functional unit defined as “the decommissioning of the Fessenheim NPP.” The system boundaries encompass four unit-processes: dismantling of electromechanical equipment, clean-up of the structures, demolition of plant buildings, and transport of conventional and radioactive waste (RW). This last unit-process is investigated separately to make a clear comparison of conventional and radioactive waste. Pre-decommissioning activities, soil rehabilitation, and RW final storage are excluded. Primary data were obtained from the decommissioning public report of EDF (Electricity of France), with scaling based on the literature and third-party reports/documents. Background processes were modeled with the ecoinvent 3.8 database. Environmental impacts are estimated using the CML-IA baseline methodology to allow comparison with previous works based on CML2001.

Results and discussion

The “Metal cutting” sub-process is found to be the major contributor to environmental impacts during dismantling, clean-up, and demolition, results varying from 62.6 to 99.5% depending on the impact category. A sensitivity analysis explores the effect of variation in shares of thermal and mechanical cutting. It demonstrates the huge potential of impact reduction for the total system under study if thermal cutting use is limited as much as possible. Despite representing only 5% of the total mass of waste, RW scores 1.8–6.6 times higher than conventional waste during transport, due to much higher distances to cover and specific conditioning. Previous explorations of results transferability are found to be methodologically uncertain, and the NPP total power installed is evaluated as an unpromising transferability factor.

Conclusions

Decommissioning of nuclear power plants is still in need of thorough studies based on exhaustive and transparent datasets. Until then, state-of-the-art prospective assessments and transferability of LCA results to future studies are severely limited. Restraint in use of oxy-acetylene cutting is nevertheless highly recommended. French unique policy regarding very low-level waste needs further consideration, and decentralized storage sites are a promising research lead.

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Acknowledgements

This work was carried out within the framework of the OHM Fessenheim. The authors acknowledge Marc Allemann and Haldan Koffi for their help in the literature review.

This work is (co)funded by OHM Fessenheim and the LabEx DRIIHM, French programme “Investissements d’Avenir” (ANR-11-LABX-0010) which is managed by the ANR. It also received funding from the CO2InnO project, which is funded by the European Union (Interreg Upper Rhine 2021–2027, A1.3).

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Conceptualization, M.K. and G.Q.; methodology, M.I., M.K., and G.Q.; data curation, M.I. and P.R.; investigation, M.I., P.R., M.B., and G.Q.; formal analysis, M.I. and P.R.; funding acquisition, G.Q.; resources, M.K. and G.Q.; software, M.K. and G.Q.; validation, P.R., M.K., M.B., and G.Q.; visualization, M.I. and P.R.; writing—original draft, M.I.; writing—review and editing, M.I., P.R., M.B., and G.Q.; supervision, M.K. and G.Q.; project administration, M.K. and G.Q. All authors have read and agreed to the published version of the manuscript.

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Iguider, M., Robineau, P., Kozderka, M. et al. Life cycle assessment of an upcoming nuclear power plant decommissioning: the Fessenheim case study from public data. Int J Life Cycle Assess (2024). https://doi.org/10.1007/s11367-024-02315-9

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How Much Is Too Little to Detect Impacts? A Case Study of a Nuclear Power Plant

Mariana mayer-pinto.

Universidade Federal do Rio de Janeiro, Instituto de Biologia, Rio de Janeiro, Rio de Janeiro, Brazil

Barbara L. Ignacio

Maria t. m. széchy, mariana s. viana, maria p. curbelo-fernandez, helena p. lavrado, andrea o. r. junqueira, eduardo vilanova, sérgio h. g. silva.

Conceived and designed the experiments: MMP BI MV MPCF AJ HL SHGS. Performed the experiments: MMP BI MV MPCF AJ HL SHGS EV MTMS. Analyzed the data: MMP. Wrote the paper: MMP BI MTMS EV AJ MV MPCF HL. Identified all the algae collected: MTMS

Associated Data

Several approaches have been proposed to assess impacts on natural assemblages. Ideally, the potentially impacted site and multiple reference sites are sampled through time, before and after the impact. Often, however, the lack of information regarding the potential overall impact, the lack of knowledge about the environment in many regions worldwide, budgets constraints and the increasing dimensions of human activities compromise the reliability of the impact assessment. We evaluated the impact, if any, and its extent of a nuclear power plant effluent on sessile epibiota assemblages using a suitable and feasible sampling design with no ‘before’ data and budget and logistic constraints. Assemblages were sampled at multiple times and at increasing distances from the point of the discharge of the effluent. There was a clear and localized effect of the power plant effluent (up to 100 m from the point of the discharge). However, depending on the time of the year, the impact reaches up to 600 m. We found a significantly lower richness of taxa in the Effluent site when compared to other sites. Furthermore, at all times, the variability of assemblages near the discharge was also smaller than in other sites. Although the sampling design used here (in particular the number of replicates) did not allow an unambiguously evaluation of the full extent of the impact in relation to its intensity and temporal variability, the multiple temporal and spatial scales used allowed the detection of some differences in the intensity of the impact, depending on the time of sampling. Our findings greatly contribute to increase the knowledge on the effects of multiple stressors caused by the effluent of a power plant and also have important implications for management strategies and conservation ecology, in general.

Introduction

Human activities are causing rapid and substantial changes to Earth’s ecosystems [1] . Most of these changes occur before knowledge about the environment is generated. There are several sampling designs and statistical approaches to assess impacts on natural assemblages and/or systems [2] , [3] . One of the most powerful ways to detect environmental impacts is the Beyond-BACI approach, where the potentially impacted site and multiple references sites are sampled through time, before and after the impact [3] , [4] . Often, however, there is no environmental data available prior to the establishment of the possible source of impact, even in non-accidental impacts such as sewage or industrial effluents. In such cases, despite some limitations in establishing cause–effect relationships between human disturbances and responses of populations and/or assemblages, it is still possible to detect impacts, if any. Similar analyses, to what is advocated by the Beyond-BACI approach [5] are then usually applied considering multiple control sites and sampling across multiple temporal scales, limited to ‘after’ times only [6] , [7] .

Assessing impacts involves another problem: the lack of information or uncertainty about the extent of the affected area. In these cases, specific gradient designs with multiple temporal samplings, at several spatial scales, are essential because they allow distinction between natural temporal changes and those due to the impact [8] , [9] . They also enable detection of changes in the variability within sites, which may be affected by impacts [3] , [10] .

Despite of the many publications available describing how to assess impacts [3] , [4] , [11] – [14] , poorly designed studies are still being done and impacts are still being erroneously or incompletely assessed (as reviewed by [15] ). This is particularly true for studies that evaluate the effects of different types of effluents on assemblages (but see e.g. [6] , [9] ).

Many coastal industries and power plants use sea-water in their cooling system and discharge this heated effluent into the sea, raising sea-water temperature in the vicinity of the discharge [16] – [18] . The effects of heated effluents seem to be more serious in tropical areas, especially in summer, when temperature of sea-water is near the upper tolerance limits of most marine organisms [19] . For example, in tropical or sub-tropical areas like Florida, India and Brazil, the increase of a few degrees in the temperature of sea-water caused by the effluents of power plants, decreased the biomass and richness of many benthic organisms [17] , [20] , [21] . Chlorine, which is deleterious for most biota, is usually added in the cooling systems to prevent fouling. In high concentrations, the chlorine released in the effluents may cause mortality and reduction in physiological activities of some benthic organisms [22] , [23] . Also, the high turbulence and flow in the vicinity of the discharge can interfere in the settlement of many invertebrate larvae [24] .

The aim of this study was to assess the impact, if any, of multiple stressors caused by the effluent of the Brazilian nuclear power plant (Central Nuclear Almirante Alvaro Alberto - CNAAA) on sessile epibiota, using a sampling design with budget and logistic constraints. We considered only the overall impact of the effluent, i.e. we did not separate the effect(s) of each stressor. At the time this field study was done, only three published studies on the effects of this power plant were found available, all on bioaccumulation on algae [25] – [27] . Only one biological study, on zooplankton, was available prior to the construction and functioning of the power plant [28] . We also use the sampling design done here as a case study to discuss the importance of appropriate and feasible sampling designs and statistical approaches to assess impacts, if any, and their extent.

The general hypotheses tested were that the power plant effluent would have an effect on the assemblages, reducing the number of species and the abundance of sessile epibiota near the discharge area and that this effect would vary in time and space. Especifically, we hypothesised that the effects of the effluent would decrease with increasing distances from the discharge area, being greater immediately next to the effluent. The effects of the effluent were also hypothesized to be greater when the average sea-water temperature in the region naturally reaches greater values (see Description of Area).

Materials and Methods

Description of area.

The CNAAA nuclear power plant discharge area (23° 07′S and 44° 26′ W) is located at Piraquara de Fora Inlet, in Ilha Grande Bay, on the southern coast of Rio de Janeiro state, Brazil. The power plant has been operating since 1985 and, at the time of this study, it consisted of two 135 U pressurised water reactors producing around 1966 MW. The cooling system demands 120 m 3 .s −1 of sea-water and the effluent discharge causes an increase in the water flow creating a current of 30 cm.s −1 near the discharge point. Chlorine is added in a concentration of 1 mg.L −1 at the heat exchangers. At the discharge area, the mean water temperature and chlorine level are 32°C and 0.04 mg.L −1 , respectively. The thermal plume forms with approximately 2 m depth. It spreads around the inlet and its extent varies depending on the capacity to which the power plant is operating and the tide and winds that constantly drive the plume for both South and North sides of the inlet [29] . Most areas of the bay have a mean water temperature of 27°C and undetectable levels of chlorine [29] . Temperature and chlorine levels were measured using a thermometer and a Merck chlorine kit, model Aquaquant 1,14434 with a precision range from 0.01 and 0.3 mg.L −1 , respectively. These measures were taken every month for 10 months, from July 2002 to April 2003, at 0.5 m depth. The area immediately near the discharge had the greatest values of temperature of sea-water, with minimum values of 28°C in September, reaching up to 36°C in summer (i.e January and February), followed by the sites 600 m away from the discharge, which had temperatures of 27°C and 32°C in winter (i.e. July) and summer, respectively. The controls (C1 and C2) had the smallest temperatures registered for all sampled sites, with minimum of 22°C in winter and maximum values of 29°C in summer. Chlorine levels showed a marked decrease with increasing distances from the discharge area, ( Figure 1 ), with the greatest values detected at the Effluent site, reaching up to 0.3 mg.L −1 in April 2003.

Measures were taken every month from July 2002 to April 2003. C1 = control 1 at the intake area; C2 = control 2– located at the East side of Brandão Island. ND = Not detected.

Experimental Design

To determine the effects of the power plant’s effluent on sessile epibiota – if any – and its spatial extent, we used a sampling design with different spatial scales at multiple times. Seven sites were sampled, with increasing distances from the point of the discharge: Effluent (Eff) –100 m from the power plant discharge point and sites located at North and South of the discharge point located at 600 m (N600 and S600, respectively) and at 1400 m (N1400 and S1400, respectively). Two control sites were also sampled: Control 1 (C1) – located at the intake area of the power plant cooling system, approximately 3 km opposite to the area of the effluent discharge; Control 2 (C2) – located at the East side of Brandão Island, approximately 3 km away from the effluent discharge point ( Figure 2 ). The control sites have the same natural type and similar slope of the susbtrata (i.e. vertical granite rocky shores) found on areas inside and around the Piraquara de Fora Inlet. These sites also present sessile assemblages similar to those commonly found in Ilha Grande Bay, except at localized disturbed areas (personal observation). No specific permits were required for the described field studies because the study did not involve destructive sampling on natural rocky shores nor any endangered or protected species.

Effluent (Eff) –100 m far from the discharge point of the power plant; 600 m sites (N600 and S600) – one on each side of the bay, 600 m far from the discharge point; 1400 m sites (N1400 and S1400) – one on each side of the bay, 1400 m far from the discharge point; Control 1 (C1) – the intake area of the cooling system, control area; Control 2 (C2) – located on the East side of Brandão Island, control area.

Four independent granite panels of 20×20 cm were placed vertically at 0.5 m depth in each site. Panels were submerged for 3 months, being replaced at the end of this period. The replacement was repeated 4 subsequent times (T1, T2, T3 and T4) from July 2002 to June 2003. Panels were sorted under a dissecting microscope and the percentage cover of sessile organisms was estimated using 100 regularly spaced points in a grid. Micro-algae and protozoa that covered the panels were described as biofilm. Although most taxa were identified to genus or species for a biological inventory (see Tables S1 and S2 ), they were combined into categories (e.g. barnacles, biofilm, ascidians and bryozoans) for statistical analyses.

Statistical Analyses

Asymmetrical univariate analyses of variance (ANOVA) were done to compare the total number of taxa and the percentage cover of the most abundant category (biofilm) among assemblages at different sites and times. Similarly, asymmetrical multivariate analyses of variance (PERMANOVA) were done to compare the structure of assemblages among sites at different times. The factors included in the analyses were: Distance, fixed; Sites, random and nested in Distance and Time, random and orthogonal. A priori contrasts were done to compare the relevant distances, i.e. because not all distances were to be compared among themselves, such as 600 m vs 1400 m, the distances to be compared were chosen a priori of the analyses (e.g. Eff vs. 600 m; Eff vs. Controls, etc.). Therefore, although the factor Distance has 4 levels in general (i.e. 100 m, 600 m, 1400 m and controls with >3000 m), in the a priori contrasts, this factor has only 2 levels (respective to the sites chosen to be compared, e.g. Eff vs Controls; see Tables in Results for further details of the analyses). When necessary, tests were done a posteriori of analyses of variance to separate significant means.

Due to the loss of several replicates at Times 3 and 4 at one of the control sites (C1), the analyses done with these sites only included Times 1 and 2, to avoid unbalanced analyses. The comparisons among the other distances (i.e. Eff vs 600 m and Eff vs 1400 m) included all the 4 sampling times (i.e. T1, T2, T3 and T4).

The variability of assemblages within and among sites was calculated using PERMDIST. This was done calculating the deviations from the centroids in each site across all sampled times and within each time [30] . The average dissimilarities among and within sites were also calculated for each time of sampling, using Bray-Curtis dissimilarity index. Analyses were done using PRIMER multi-package 6.0. The univariate analyses of variance were also done using PRIMER to standardize the way the analyses were done (since no uni-variate statistical package can do asymmetrical analyses withouth partitioning the Sum of Squares; see e.g. [5] , [13] ). For the univariate analyses, Euclidean distance was used instead of Bray-Curtis (index used in the multivariate analyses).

Thirty-five taxa of macro-algae were recorded; 1 taxon at Effluent site, 20 at N600, 19 at S600, 16 at N1400, 21 at S1400, 9 at C1 and 12 at C2 site ( Table S1 ). A total of 51 taxa of invertebrates were recorded, 1 taxon at Effluent site, 31 at N600, 20 at S600, 29 at N1400, 29 at S1400, 24 at C1 and 27 at C2 site ( Table S2 ). No macroscopic taxon was found at all studied sites. The anemone Haliplanella was the only taxon exclusively found at the two control sites, whereas the Chlorophyta Boodleopsis vaucherioidea was just recorded at the two 600 m sites. No particular taxon was exclusively recorded at both 1400 m sites. Sabellidae (Polychaeta), the category Amphipods tubes and the sponge Scopalina ruetzieri were found at all sites at 600 m and 1400 m, however, these taxa were not found at the control sites ( Tables S1 and S2 ).

Except for the Effluent site, the number of taxa within and among sites varied in time ( Figure 3 ). At all times, the number of taxa was significantly smaller at the Effluent than at all the other studied sites ( p <0.05, for values of F, please refer to Table 1 ). There were no significant differences among the 600 m and 1400 m sites with the controls (p>0.05; for values of F, please refer to Table 2 ).

Note that in times T3 and T4, only one control (C2) was sampled due to losses of replicates.

Covers of biofilm (which reflects a lack of recruitment of macro-organisms) showed great temporal and spatial variation (except at the Effluent), being greater at Time 1 than at other times of sampling ( p <0.05; Figure 4 ). Biofilm cover was ∼100% at all sampling times at the Effluent site. Its cover was always significantly greater at the Effluent site when compared to the 600 and 1400 m sites ( p <0.05; for values of F , please refer to Table 3 ). Control sites showed smaller values of cover of biofilm ( Figure 4 ); however, statistical analyses showed no significant differences among the controls and the other sites, including the Effluent ( p >0.05; for values of F please refer to Tables 3 and ​ and4, 4 , please note that only Times 1 and 2 were analysed). The average dissimilarity among and within sites showed, however, a great difference of cover of biofilm among the Effluent and the control sites, with a dissimilarity among sites of approximately 98% at Time 2 ( Table 5 ).

Note that in times T3 and T4, only one control (C2) was sampled due to losses of replicates. Black bars = T1; White bars = T2; Grey bars = T3; Striped bars = T4.

Considering the whole assemblages, there was a great variability among sites and times (shown by the interaction Si (Di) X Ti; Tables 6 and ​ and7). 7 ). Despite of this variability, there was a clear difference among the Effluent site and the 600 m and 1400 m sites (Distance - p <0.05; for values of F , please refer to Table 6 ; Figure 5 ). The comparison between the Effluent and the control sites showed a significant interaction between Distance and Time ( p <0.05; for values of F , please refer to Table 6 ), with the Effuent differing from the controls at Time 2 ( a posteriori tests, Table 6 ). The 600 m sites significantly differed from the controls, but, similarly to the Effluent site, this difference was only significant at one of the two times analysed (i.e. Time 2; p <0.05; Table 7 ).

Full symbols are to show sites on the same side of the bay (i.e. N or S) and to differentiate both controls (filled circles are control 1 - the intake, and empty circles are control 2). n  = 4; Note that in times 3 and 4, only one control site (C2) was sampled due to losses of replicates.

In contrast, no significant differences were found between the controls and the sites 1400 m away from the discharge area in any of the analysed times.

There was a great variation within sites at Time 1, except at the Effluent site. At this time, the average dissimilarities within the 1400 m sites were greater than the dissimilarities among them and the Effluent site (23.3 and 16.6, respectively; Table 8 ). In contrast, the control sites (C1 and C2) showed ∼50% dissimilarity from all other sites, forming a distinct group ( Table 8 ; Figure 5 ).

The Effluent site had the smallest variability compared to all other sites, at all times. The variability of the assemblages varied greatly with time in all sites, except the Effluent ( Figure 6 ).

The deviations from the centroids in each site were calculated within each time. Black bars = T1; White bars = T2; Crossed bars = T3; Striped bars = T4. n  = 4 at the Effuent and 8 at the other sites; Note that in Time 3 and 4, only one control site (C2) was analyzed due to losses of replicates.

Management actions, restoration efforts and even court penalties are, many times, a result of scientific information on detection of impacts and their consequences to the environment. Thus, the difficulty, or even inability, to detect an impact may have serious ecological and social consequences since contamination of natural systems, loss of diversity and ecosystem functions and benefits might be occurring with no legal penalties.

Suitable experiments, using appropriate designs and relevant spatial scales are necessary to properly assess impacts. In this study, a clear and localized effect of the power plant effluent – up to 100 m from the point of the discharge (i.e. Effluent site) – was found on the sessile epibiota. This was evident by differences concerning the total number of species, the biofilm cover and the variability of assemblages. The most obvious effect of the impact was the lack of macro-organisms on the Effluent site when compared to other parts of the bay, which could be due to impacts on settlement and/or post-settlement processes.

Despite the great variability found within sites (except for the Effluent site) and between times of sampling, the analyses of variance (specifically the multivariate ones) clearly showed a localized effect (up to 100 m from the point of the discharge) of the effluent on the sessile epibiota. Furthermore, it also showed that the impact can sometimes reaches up to 600 m of the discharge point, as demonstrated by the analyses at one of the four sampling times of this study.

The stressors of the nuclear power plant discharge (temperature, chlorine and flow) are recognized factors influencing the survival of invertebrate and macro-algae. The influence of temperature on distribution and abundance of several organisms is probably the most well-known of them [31] , [32] , [33] and one of the factors of main concern on the effects of climate change on natural systems [34] , [35] . Changes in the composition and abundance of many species of algae and invertebrates, in California, have been attributed to the effect of an increase in sea-water temperature due to a heated power plant outfall [11] , [36] . Similarly, near the effluent of a power plant in Florida, a 50% reduction of molluscan and crustacean taxa was observed at 33°C and a 75% reduction at 37°C [20] . In the effluent area of a nuclear power plant in India, almost the entire epifauna and macro-flora were eliminated at 37°C [17] . At the Effluent site studied here, temperature of sea-water reached up to 36°C, which could be one of the main factors for the lack of macro-organisms found at the site.

Chlorine has also been shown to have negative effects on many organisms [37] , [38] . Concentrations of this contaminant similar to those found at the Efluent site (i.e. 0.1 mg.L −1 ) have been shown to decrease recruitment of bivalves [23] . Furthermore, the effluent studied here caused an increase in the flow of water in the area near the discharge point, creating a current of 30 cm.s −1 (data supplied by CNAAA). The flow of water may affect settlement of organisms by i) exerting hydrodynamic forces on settling propagules, ii) providing a settlement cue that induces active behaviour of motile propagules or iii) it may act to mediate various settlement cues [e.g. influencing sedimentation and chemical cues; 24]. High velocity water flow, such as those found near the power plant discharge point, can therefore reduce settlement of many species of organisms [24] .

The multiple stressors of the power plant discharge studied here caused an impact on the sessile benthic assemblages at 100 m away from the discharge area (Effluent site). This impact varied in intensity depending on the time of the year, reaching up to 600 m at Time 2. Although at Time 1 there were no significant differences in the assemblages among the Effluent and the controls, this is probably due to the number of replicates used here (n = 4) and the great variation found within the assemblages at the control sites at this time. The number of taxa recorded in each site and the average dissimilarities among sites do suggest, however, a clear impact at the Effluent site at all times analysed. Furthermore, at all times, the variability within the Effluent site was also smaller than in other sites (i.e. 600 m, 1400 m and control sites). Environmental disturbances can affect variance instead of the means of biological variables, i.e. temporal and spatial variability inherent to natural assemblages may be affected by impacts [3] , [10] . Similarly to the Effluent site, there were significant differences in the structure of assemblages among the sites 600 m away from the discharge area and the control sites at only one of the two analysed times.

No significant differences between the controls and 1400 m sites were found. This could be due to an actual lack of effect of the effluent at this distance or simply due to a lack of power of the analyses. Considering that, at those sites, sea-water temperature and chlorine levels were greater than at the control sites and that the qualitative and descriptive analyses (such as the nMDS and the composition of species in each site) suggest some differences among these sites and the controls, it is possible that these differences were not detected by the analyses of variance due to the low number of replicates used. Furthermore, only two times of sampling were analysed in comparisons with the control sites (due to losses of replicates, instead of the 4 times analysed in comparisons with the other distances); and there was a great variation found within the assemblages at the controls sites (especially at Time 1). To establish, with some certainty, whether the (more subtle) effects, if any, of the effluent did actually reach greater distances than those found here (i.e. up to 600 m depending on the time of the year), a greater number of replicates and/or sampling times should have been used. In addition, although the sampling design used was appropriate for the hypotheses being tested (i.e. the effluent has an impact on assemblages and this impact varies in time and according to distance form the discharge), it does not allow determining changes in spatial variation of the impact. For that, the spatial scales at which sampling was done within the bay with the outfall would need to be replicated at each of two control sites.

Budget and logistic constraints are, unfortunately, relevant in many situations regarding environmental impact assessments, especially in developing countries, making it very hard to apply what would be considered ‘ideal’ sampling designs. Extra-care should be taken in experimental designs that suffer budget and logistic constraints because, even with limited funding, parts of the sampling design cannot be eliminated or simplified without leading to an incomplete or erroneous environmental assessment. Low-budget studies that lack appropriate controls and replicates, may end up, in reality, costing more because they cannot determine whether an impact is, in fact, occurring or not. In this study, the strong impact of the power plant effluent on the sessile assemblages at 100 m of the discharge point (Effluent site) could probably have been detected even using simpler sampling designs. However, although the design used here (in particular the number of replicates) did not allow an unambiguously evaluation of the full extent of the impact caused by the power plant discharge in relation to its intensity and temporal variability, the multiple temporal and spatial scales used allowed the detection of some differences in its intensity and temporal variability.

Our findings have important implications for management strategies, not only of the Brazilian nuclear power plant, but also for management and conservation ecology in general. We emphasize that evidence-based knowledge is critical for building effective impact evaluation (considering its extent, intensity and spatial and temporal variation) to define monitoring strategies for basic or applied ecology.

Supporting Information

Taxa of macro-algae found in each sampled site across all times.

Taxa of invertebrates found in each sampled site across all times.

Acknowledgments

The authors thank A.J. Underwood for all the help regarding the analyses and for critical comments of an earlier version of this manuscript. The authors are in debt with Marti J. Anderson for all the help with multivariate analyses and PERMANOVA. We also thank E.M. Marzinelli, M. Matias, P. Morais, S. López and A.Verges for all the discussions and helpful comments. We thank everyone that helped with the field work, especially J. Valerio da Costa. Editor and two anonymous referees greatly contributed to improve this manuscript.

Funding Statement

This study was supported by the National Counsel of Technological and Scientific Development (CNPq) to Silva, S.H.G. The funder had no role in study design, data collection and analysis, decision to publish, or preparation of the manuscript.

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Home > Books > Nuclear Reactors - Spacecraft Propulsion, Research Reactors, and Reactor Analysis Topics

Reliability Analysis of Instrumentation and Control System: A Case Study of Nuclear Power Plant

Submitted: 02 September 2021 Reviewed: 06 October 2021 Published: 30 November 2021

DOI: 10.5772/intechopen.101099

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Instrumentation and control system (I&Cs) plays a key role in nuclear power plants (NPP) whose failure may cause the major issue in a form of accidents, hazardous radiations, and environmental loss. That is why importantly ensure the reliability of such system in NPP. In this proposed method, we effectively analyze the reliability of the instrumentation and control system. An isolation condenser system of nuclear power plant is taken as a case study to show the analysis. The methodology includes the dynamic behavior of the system using Petri net. The proposed method is validated on operation data of NPP.

• reliability
• control system
• nuclear power plant
• isolation condenser system

Author Information

Mohan rao mamdikar.

• National Institute of Technology, India

Vinay Kumar *

Pooja singh.

• VJIT, India

*Address all correspondence to: [email protected]

1. Introduction

Instrumentation and control system (I&C) plays a vital role in the field of the nuclear industry. Nowadays I&C systems are embedded into the nuclear power plant (NPP) operation and reliability. Each component of NPP, such as transformers, valves, circuit breakers, heat exchangers. is equipped with digital I&C system whose reliability plays a vital role to avoid any accidents. Because these components are safety-critical systems (SCS) whose failure may cause huge losses in the form of economic loss, human resource damage, and environmental loss. As instrumentation and control systems are the important and first layer of safety, reliability, and stability in the NPP [ 1 ] that is the reason, it is essential to ensure the reliability of such a safety system. With, the introduction of digital control systems in the last few decades where the reliability of digital I&C must not be degraded. Therefore, researchers are rigorously working to address the dependability of the system. The dependability includes reliability, safety analysis, performance, and availability attributes that are ultimately related to security. The model checking may be used to various issues, which can lead to spurious actuation of the I&C system [ 2 ]. The transformation from analog to digital I&C safety systems added new challenges for researchers as well as software developers to deliver correct software reliability [ 3 ]. Based on this software experts could take essential steps early in the design phase of software by avoiding failures in I&C of NPP. The cyberattack occurred in the I&C system in the Iranian Bushehr nuclear power plant, where configure was destroyed by malicious code [ 4 ]. Therefore, it is essential to I&C systems required having secure and reliable to avoid any kind of attacks causing major accidents. Many researchers have put efforts to address the reliability analysis on such systems using various techniques, such as fault tree analysis (FTA), reliability block diagram (RBD), Bayesian network, etc.

This work proposes the reliability analysis of instrumentation and control system (I&C) of NPP using stochastic Petri net (SPN).

The organization of this paper is as follows. In Section 2, our focus is on the related work of the proposed work. In Section 3, we discuss the background and mathematical fundamentals. In Section 4, proposes the framework of the proposed method. In Section 5, the case study of the proposed work. In Section 6, reliability analysis of the proposed work. In Section 7, the validation part is covered. In Section 8, the conclusion is made with future work.

2. Related work

Zeller et al. [ 5 ] proposed a combined approach of Markov chain and component fault tree to analyze the complex software-controlled system in the automotive domain. The authors have addressed safety and reliability in modular form. However, authors have missed to validate the result and failed to express reliability accuracy in percentage.

Nidhin et al. [ 6 ] presented a survey for understanding radiation effects in SRAM-based FPGAs for implementing I&C of NPP. Authors have found that for implementing NPP with I&C in SRAM-based FPGAs, the effect of radiation issue is a major concern. To reduce radiation-related issues some components, which have SRAM-based FPGAs, must keep outside of reactor containment building (RCB). However, the authors have failed to discuss the case study.

Jia et al. [ 7 ] proposed an approach for the identification of vulnerabilities present in elements that affect the reliability of digital instrumentation and control system (DI&C) software life cycle using Bayesian network. A reliability demonstration of safety-critical software (RDSS) integrates the claim-argument-evidence (CAE) and sensitivity to estimate the reliability of the system. However, there is a limitation with BN that has no time constraints and dynamic property. Authors have missed addressing the reliability with validation from the real-time dataset.

Rejzek and Hilbes [ 8 ] proposed system-theoretic process analysis (STPA) for design verification and risk analysis of digital I&C of NPP. This method is considered as a prominent approach for analysis of the I&C system theoretically as the authors claim. However, the authors are not very much sure, that method correct result.

Torkey et al. [ 9 ] proposed a reliability improvement framework of the digital reactor protection system by transforming reliability block diagram to Bayesian belief network (BBN). The proposed method gives the highest availability as a result and found some modules are riskier than others of I&C. However, authors claim that it gives the highest availability but missed to validate the result with real-time data.

Kumar et al. [ 3 ] proposed a framework for predicting the reliability of the safety-critical and control system using the Bayesian update methodology. The authors have validated the result with real-time data of 12 safety-critical control systems of NPP. However, the result obtained is purely based on the failure data, if failure data is unavailable then it is difficult to predict the reliability.

Mamdikar et al. [ 10 ] devise a framework for reliability analysis, performance analysis that maps unified modified language (UML) to Petri net. The proposed framework is validated with 32 safety-critical systems of NPP. However, Petri net has a state space explosion problem as a system grows gradually, so it is not a generalized approach.

Nayak et al. [ 11 ] proposed a methodology called assessment of passive system reliability (APSRA) is used to estimate the reliability of the passive isolation condenser system of the Indian advanced heavy water reactor (AHWR). In this methodology, reliability is estimated through PSA treatment using generic data of the component. A classical fault tree analysis is used to find the root cause of the critical parameter, which leads to failure. However, the authors have failed to validate the result.

Kumar et al. [ 12 ] proposed a safety analysis framework that maps UML into the state-space model as Petri net of the safety-critical system of NPP. In this methodology, the result is validated on 29 different safety-critical systems of NPP. However, the authors have used Petri net that has a state space explosion problem.

Tripathi et al. [ 13 ] proposed a noble methodology dynamic reliability analysis of the passive decay heat removal system of NPP using Petri net. The authors have validated the estimated reliability based on the data available using fault tree analysis. Most of the system does not have such type data, and then it is difficult to validate the result with missing failure data. Therefore, this methodology may not applicable for every safety-critical system of NPP.

Buzhinsky and Pakonen [ 14 ] proposed an automated symmetry breaking approach for checking failure tolerance of I&C system. With this method a fewer failure combination has to be checked. The complex structure paired with various specifications has to be checked under failure assumptions, which is the limitation of this work.

Singh et al. [ 15 ] proposed a system modeling strategy for design verification of I&C of nuclear power plant using Petri net and converting PN into Markov chain. In this approach, verification is validated on real-time data. However, Petri net has a state-space explosion problem, in such circumstances, it is difficult to handle complex systems, which is the limitation of the work.

Xi et al. [ 16 ] proposed a test strategy based on the random selection of logic path by which provides reliability estimation and is used for control system testing in digital control software systems in the NPP. However, the authors have not been addressed and validated the reliability evaluation.

Bao et al. [ 17 ] proposed hazard analysis for identifying common cause failure of digital I&C using redundancy guided system in NPP. To conduct using redundancy guided systems, theoretic hazard analysis a modularized approach was applied. This method is helpful to remove casual effects of potential single points of failure that exist in I&C. However, authors have missed addressing the reliability analysis using this methodology in NPP.

Gupta et al. [ 1 ] proposed a method for stability analysis and steady-state analysis of the safety system of NPP using Petri net. The stability and steady-state were estimated and validated, however, authors have missed estimating reliability. The authors have to correlate stability with reliability. Further, this methodology is applicable only for discrete-time systems.

3. Background and mathematical fundamentals

This section consists of background and mathematical fundamentals to carry out reliability analysis of instrumentation and control system: a case study of nuclear power plant.

3.1 Petri net

A Petri net (PN) is mathematically defined 5-tuple PN = P T F W M 0 where P the finite is set places, T is a finite set of transitions, F is a finite set of arcs also referred to as flow relation, i.e., F ⊆ P × T ∪ T × P , W : F ⟶ 1 2 3 … . is the weight function, and M 0 is the initial marking M 0 : P ⟶ 0 1 2 3 … . . P ∩ T = ∅ and P ∩ T ≠ ∅ . If the Petri net does not have an initial marking, it is denoted as N = P T F W with an initial marking denoted by N M 0 . A simple example of the PN is shown in Figure 1 .

A transition in the enable mode when each input place of p of t is marked with at least w p t tokens.

An enabled transition is not necessarily fired.

A firing of enabled transition removes tokens from the input place and deposited in the output place.

3.2 Stochastic Petri net

A stochastic Petri net (SPN) is the extension of Petri net. In SPN, each transition is associated with a time delay that is an exponentially distributed random variable that expresses delay denoted by SPN = P T F W M 0 .

3.3 Reachability

Reachability is the fundamental study of the dynamic property of the system. A marking M n is said to be reachable from another marking M 1 if there exists a firing sequence that transforms M n to M 1 such that ∂ = M 1 t 0 M 2 t 1 M 3 … . t n M n .

3.4 Reachability graph and Markov chain (MC)

A marking M is reachable from the initial marking M 0 if there exists a firing ∂ that brings back from the initial state of PN to a state that corresponds to M 0 .

The Markov chain (MC) is the Markov process with discrete state space. The MC is obtained from the reachability graph of the SPN. Let SPN be the reversible, i.e., M 0 ∈ R M i for every M i in R M 0 , then the SPN generates an ergodic continuous time Markov chain (CTMC) and it is possible to compute the steady-state probability distribution ∏ by solving the following ( Eq. (1) ) and ( Eq. (2) ).

Where, π i is the probability being in the state M i and ∏ = π 1 π 2 … π s .

4. Framework of the proposed method

The proposed framework has six steps shown in Figure 2 . Step 1—based on the system requirement we model the stochastic Petri net.

Simple Petri net.

In step 2—by executing the PN model, we generate possible tangible states. Based on the tangible states, we construct the reachability graph in step 3. In step 4—obtained Markov chain form reachability, the graph of SPN. In step 5, we estimate the reliability of the ISO system. In step 6, we validate the result with real-time operation data of NPP.

5. Case study: Isolation condenser system (ISO)

The isolation condenser system simply referred to as ISO is a standby high-pressure system that removes residual and decay heat from the reactor vessel in the event of a scram signal in which the reactor becomes isolated from the main condenser, or if any other high-pressure condition exists. The schematic diagram is shown in Figure 3 . The ISO system transfers residual and decays heat from the reactor coolant to the water in the shell side of the isolation condenser resulting in steam generation (SG). The steam generated in the shell side of the isolation condenser is then vented to the outside atmosphere. During the normal operation, the ISO system is in standby mode. During the standby mode, the steam isolation valves (VS1 and VS2) are open because the condenser tube bundles are at the reactor pressure. The condensate is built in the condenser and condensate by returning pipe. The condensate is stopped from a return back to the reactor by closing the condensate return valve (V C2 ). The condensate valve (V C1 ) is open at the stand-by condition and vent valves (VV) at main steam lines normally open to vent noncondensable gases from ISO. The makeup water must be provided to prevent uncovering the condenser tubes that are the combination of firewater and condensate using makeup water valve (V W ) normally closed at standby mode. The water inventory on the shell side of the condenser will provide heat removal for between 20 and 90 minutes depending on the plant design, at which time makeup water must be provided to prevent uncovering the condenser tubes. On the shell side of the condenser, the water inventory will be provided for the heat removal between 20 to 90 minutes. At which time water makeup has to be provided to prevent uncovering the condenser system tubes ( Figure 3 ).

Proposed framework of the system.

Schematic diagram of isolation condenser system.

The ISO system may be initiated manually, or automatically initiated on high reactor pressure or low reactor pressure. On the initiation of ISO, one of the condensate return valves (V C2 ) opens and the vent valve (V V ) gets closed. The steam flows from the reactor vessel to steam isolation valves (V S1 and V S2 ). The steam gets condensed in condenser tube bundles and condensed steam returns to the reactor vessel (V C2 and V C2 ) with help of a recirculation pump. The boiled-off water is replaced by the condensate transfer system or the firewater system. The ISO system is designed in such a way that, the system automatically gets isolated from the reactor pressure vessel in the event of a system pipe break. All the valves are closed automatically (V S1 , V S2 , V C2 , V C2 , and V V ) in the event of low differential pressure exceeds three times the normal flow value. This isolation will mitigate the loss of water inventory. The ISO system instrumentation and control consists of initiation and containment isolation circuitry [ 18 ]. These circuits provide different functions, both of which are important to system reliability. The entire system is operating in a closed-loop manner.

6. Proposed framework of approach

To estimate the reliability by our approach of the ISO which consist of six steps as shown in Figure 2 as described step by step as follows:

6.1 PN model generation

In this phase, we construct the PN model of ISO system based on system requirements and specifications. As several researchers have proposed methods [ 19 ], based on that we generated a PN model. Based on functional requirements, the activity involves the PN generation to identify the places and transitions of the case study: ISO system. The identified places and transitions as illustrated in Table 1 .

ISO places and transitions based on function specification.

Thereafter, we use the TimeNet4.5 [ 20 ] tool for SPN creation. Then we assign the transition delay to the transition based on the system requirement. To get throughput values of transition stationary analysis was performed in the TimeNet tool as shown in Table 2 .

ISO throughput values.

The PN model was generated using TimeNet tools shown in Figure 4 .

PN model of ISO.

6.2 Tangible states and reachability graph creation

Tangible states are those for timed transitions [ 21 ], since we used SPN so there are e tangible states with markings as shown in Table 3 .

ISO tangible states with markings of PN.

Based on the tangible states of the PN a reachability graph of the PN ( Figure 4 ) can be obtained as shown in Figure 5 .

Reachability graph.

6.3 Markov chain model creation

The MC model shown in Figure 6 is obtained from the reachability graph of the PN shown in Figure 4 .

Markov chain.

With the help of Q which is transition probability matrix, the transition probability P ij of MC can be computed from SPN. For the transition matrix Q , transitionrate q ij is the transition of one state to another states unit/per time, therefore we take the ratio of the transition q ij and the transition rate of the states sum must be zero. The diagonal elements can be defined as:

It is clear that the system is no ergodic, therefore, P ij will be zero and defined as:

P = I − d Q − 1 Q , where d Q = dia Q diagonal matrix of Q .

The transition matrix is given in Eq. (5) as follows:

Now we solve Eq. (5) to get the design metrics and it seriousness of the NPP as defined in Eq. (6) . We solve the Eq. (6) then we get the following linear equations.

6.4 Reliability analysis of proposed framework

Let p i t be the probability which component in state at time t is i . When components execute for t → ∞ then probability leads to the stationary distribution. Then probability is defined as:

There is only one failure state M 6 in MC. Now we solve the linear equation Eqs. (7) - (16) and Eq. (17) using the standard method, we get steady-state probability of each state as follows:

M 0 = 0.1282051 , M 1 = 0.1282051 , M 2 = 0.1282051 , M 3 = 0.1282051 , M 4 = 0.1282051 , M 5 = 0.1282051 , M 6 = 0.025641, M 7 = 0.1025641, and M 8 = 0.1025641

Hence the reliability of ISO is:

7. Validation of proposed framework

In section, we compute the rate of failure to ensure the result experimentally of the proposed framework and follow the six steps for reliability estimation [ 10 , 22 ]. We divide the entire input class into several subclass and for estimating reliability following equation required as:

P e i is the probability specified from input operation data. n i is the number of trials from each comparable class. h i is a number of trial cases that are failed.

To estimate the actual reliability Table 4 data will be used.

Reliability estimation using [ 22 ].

Now using Eq. (22) we estimate actual reliability as:

Now we compare estimated (predicted) and actual reliability as:

Hence, the error percentages can be computed as:

Hence, the accuracy of proposed reliability computed of proposed framework is 100 − error % = 98.4201 % that indicates the validation of our work.

8. Conclusion

The proposed method is centered technique for computing reliability of instrumentation and control system of the safety-critical system of NPP. We have validated the result with operational and found accuracy with 98.4201 % . With this method, software designers take necessary preventive measures early design phase to avoid any kind of failure.

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Nuclear Proliferation Case Studies

Appendix to safeguards to prevent nuclear proliferation.

(Updated March 2019)

• North Korea made weapons-grade plutonium using a research reactor and a reprocessing plant in defiance of its NPT obligations. In 2006, 2009, 2013 and 2016 it exploded five nuclear devices.
• In 2002 Iran's previously undeclared nuclear facilities became the subject of IAEA inquiry, which established that it appeared to be in violation of its NPT safeguards agreement. It continued uranium enrichment in defiance of the UN Security Council.
• Iraq to 1991 attempted to enrich indigenous uranium to weapons-grade material, in violation of NPT and safeguards obligations.
• Syria constructed a nuclear reactor in breach of its NPT obligations.

Up to the late 1980s it was generally assumed that any undeclared nuclear activities would have to be based on the diversion of nuclear material from safeguards. States acknowledged the possibility of nuclear activities entirely separate from those covered by safeguards, but it was assumed they would be detected by national intelligence activities. There was no particular effort requiring the IAEA to attempt to detect them.

Not until the 1990 NPT Review Conference did some states raise the possibility of making more use of the provisions for "special inspections" in existing NPT Safeguards Agreements, for example. Special inspections can be undertaken at locations other than those where safeguards routinely apply, if there is reason to believe there may be undeclared material or activities.

However, inspections in Iraq following the 1991 UN Gulf War cease-fire resolution showed the extent of Iraq's clandestine nuclear weapons program, and it became clear that the IAEA would have to broaden the scope of its activities. Iraq was an NPT Party, and had thus agreed to place all its nuclear material under IAEA safeguards. But the inspections revealed that it had been pursuing an extensive clandestine uranium enrichment programme, as well as a nuclear weapons design programme.

The revelations from Iraq provided the impetus for a very far-reaching reconsideration of what safeguards are intended to achieve. (See the section on Addressing Undeclared Nuclear Activities in the main paper on Safeguards to Prevent Nuclear Proliferation .)

North Korea

The Democratic People’s Republic of Korea (DPRK) provides an example of safeguards succeeding in their aim of detecting violations of non-proliferation obligations – in this case one of long standing. It was subsequently brought to the attention of the international community, with diplomatic pressure being applied through the UN Security Council.

The DPRK acceded to the NPT in 1985 as a condition for the supply of a nuclear power station by the then USSR. However, it delayed concluding its NPT Safeguards Agreement with the IAEA, a process which should take only 18 months, until April 1992. This delay was apparently related to the presence of US tactical nuclear weapons in South Korea, which were withdrawn in 1992. IAEA inspections then showed up some problems.

Plutonium program

During that period, in late 1985, North Korea brought into operation a small gas-cooled (CO 2 ), graphite-moderated, natural-uranium (metal) fuelled "Experimental Power Reactor" of about 25 MWt at Yongbyon, on the west coast 55 km north of Pyongyang. It exhibited all the features of a plutonium production reactor for weapons purposes and produced only about 5 MWe. North Korea also made substantial progress in the construction of two larger reactors designed on the same principles, a prototype of about 200 MWt (50 MWe) at Yongbyon, construction started 1985, and a full-scale version of about 800 MWt (200 MWe) at Taechon, 25 km north of Yongbyon.

In addition it completed and commissioned a reprocessing plant at Yongbyon for the extraction of plutonium from spent reactor fuel. That plutonium, if the fuel was only irradiated to a very low burn-up, would have been in a form very suitable for weapons. The existence of the plant was revealed by IAEA inspectors. Although all these facilities at Yongbyon were to be under safeguards, there was always the risk that at some stage, the DPRK would withdraw from the NPT on some pretext and use the plutonium for weapons.

One of the first steps in applying NPT safeguards is for the IAEA to verify the initial stocks of uranium and plutonium to ensure that all the nuclear material in the country have been declared for safeguards purposes. While undertaking this work in 1992, IAEA inspectors found discrepancies which indicated that the reprocessing plant had been used more often than the DPRK had declared. This suggested that the DPRK could have weapons-grade plutonium which it had not declared to the IAEA. Information passed to the IAEA by a member state (as required under the IAEA's Statute) supported that suggestion by indicating that the DPRK had two undeclared waste or other storage sites.

In February 1993 the IAEA called on the DPRK to allow special inspections of the two sites so that the initial stocks of nuclear material could be verified. The DPRK refused, and on 12 March announced its intention to withdraw from the NPT (three months notice is required). In April 1993 the IAEA Board concluded that the DPRK was in non-compliance with its safeguards obligations and reported the matter to the UN Security Council. In June 1993 the DPRK announced that it had "suspended" its withdrawal from the NPT, but subsequently claimed a "special status" with respect to its safeguards obligations. This was rejected by IAEA.

Once the DPRK's non-compliance had been reported to the UN Security Council, the essential part of the IAEA's mission had been completed. Inspections in the DPRK continued, although inspectors were increasingly hampered in what they were permitted to do by the DPRK's claim of a "special status". However, some 8,000 corroding fuel rods associated with the experimental reactor remained under close surveillance and any plans to separate plutonium from them were deferred, in the event, for eight years.

Following bilateral negotiations between the DPRK and the USA, and the conclusion of the agreed framework in October 1994, the IAEA was given additional responsibilities. The agreement required a freeze on the operation and construction of the DPRK's plutonium production reactors and their related facilities, and the IAEA was responsible for monitoring the freeze until the facilities were eventually dismantled. The DPRK remained uncooperative with the IAEA verification work and did not comply with its safeguards agreement, though apparently no further work was done on the two larger reactors at Yongbyon and Taechon.

Iraq was defeated in a war, which gave the UN the opportunity to seek out and destroy its nuclear weapons program as part of the cease-fire conditions. The DPRK was not defeated, nor was it vulnerable to other measures, such as trade sanctions. It could scarcely afford to import anything, and sanctions on vital commodities, such as oil, would either have been ineffective, or risk provoking war.

Ultimately, the DPRK was persuaded to halt its nuclear weapons program in the 1990s in exchange, under the agreed framework, for about $US5 billion in energy-related assistance. This included two 1000 MWe light water nuclear power reactors. There was also the prospect of diplomatic and economic relations with the USA.

Light-water reactors offered

At the end of 1999 The long-awaited contract to build two 1000 MWe light-water reactors was signed, enabling construction to begin. The agreement was between the Korean peninsula Economic Development Organisation (KEDO) – the international organisation in charge of the project – and the South Korean utility KEPCO, bringing technology to build a nuclear power plant which is not amenable to misuse. KEDO was set up following the 1994 deal involving the USA to head off the production of weapons plutonium from the small gas-graphite reactor and to provide much needed energy – in the short term fuel oil, but eventually electricity.

The Korean Standard Nuclear Plant (KSNP) reactors were the same as those then being built in South Korea, and were expected to be completed in 2008. South Korea committed to provide US$ 3.22 billion for the US$ 4.6 billion project, with Japan contributing US$ 1 billion and the EU most of the balance.

In August 2002, with the project running several years behind schedule due to North Korea's continued lack of cooperation with the IAEA in verifying the history of its nuclear program, first concrete for the two-unit nuclear power plant was poured at Kumho, on the east coast. This formal start of construction was a milestone for KEDO, which planned to deliver the main components in 2005. The work would then stop unless North Korea was fully compliant with IAEA requirements regarding verification of past activities (specifically, that all nuclear material held by North Korea has been declared and placed under safeguards).

Plutonium program revived

In December 2002 the DPRK removed the IAEA seals on its facilities at Yongbyon and ordered the IAEA inspectors out of the country. It then restarted its small reactor and commenced reprocessing the 8000 irradiated fuel rods to recover weapons-grade plutonium. In April 2003 it withdrew from the NPT – the first and only country to do so.

Since 2003 negotiations have been intermittently under way to secure some agreement on curtailing North Korea's nuclear weapons program. These have involved China, South Korea, Japan, Russia and the USA, which insisted upon "complete, verifiable, and irreversible dismantling of North Korea's weapons programs" through "diplomatic dialogue in a multilateral framework involving those states with the most direct stakes in the outcome."

Construction of the new nuclear power reactors under KEDO was suspended late in 2003 with the first unit about 30% complete, and this suspension was renewed in 2004 and 2005. The KEDO board formally terminated the project in May 2006. Most of the fabrication of steam generators, pressure vessels and other equipment for both reactors was ready to install. This equipment was redeployed by KEPCO.

In October 2006 the DPRK tested a nuclear weapon underground at Punggye-ri, 50 km northwest of Gilju/Kilju in the northeast of the country, and the whole matter was referred to the UN Security Council.

After several attempts at negotiation, in February 2007 agreement with the DPRK was reached in the six-party talks involving China, Japan, Russia, South Korea and the USA. This involved DPRK agreeing to shut down and seal the Yongbyon reactor and related facilities including reprocessing plant within 60 days (by 14 April) and accepting IAEA monitoring of this, in return for assistance with its energy needs. Further assistance would follow the irreversible disabling of the reactor and all other nuclear facilities. The April 14 deadline was missed. After further diplomatic efforts, the reactor was shut down in mid July 2007 and an IAEA team was able to verify this and in addition, that other nuclear facilities at the site were also closed, notably the reprocessing plant ("Radiochemical Laboratory") and fuel fabrication plant. These were sealed and were to be subject to ongoing monitoring by IAEA. It was proposed to send the used fuel to Mayak in Russia or Sellafield in UK for reprocessing (required because the used fuel elements were chemically unstable). Any separated plutonium would not be repatriated.

The second phase of measures under the February 2007 agreement involved establishing a full inventory of nuclear materials and actually disabling the offending plants – initially promised by end of December 2007 but dragged out to June 2008 and then marked by demolition of Yongbyon's cooling tower. Phase 3 would be when North Korea hands over fissile materials and weapons gear. North Korea has raised the question of reviving the KEDO project for building a light water reactor.

In September 2008 North Korea refused to accept verification procedures and threatened to restart its Yongbyon reprocessing plant. The six parties met in December 2008 but did not reach agreement on verification, though removal of fuel rods from the Yongbyon reactor continued. Then North Korea expelled IAEA inspectors, restarted reprocessing at Yongbyon, and in May 2009 it exploded another nuclear device underground at Punggye-ri, possibly more successfully than 2006, with yield of about 2 kilotonnes TNT (cf Hiroshima 15 kt).

In February 2013 North Korea exploded a third nuclear device underground, with slightly higher yield than the earlier ones. It is not clear whether it used uranium or plutonium.

In May 2013 it appeared that the Yongbyon 25 MWt reactor was being prepared for recommissioning. A new cooling system for the reactor had been built and two tanks holding used fuel had been covered. Activity at the site continued. In September 2013 and early in 2014 there were indications that the reactor had restarted. In mid-2014 and again in January 2016 the Institute for Science and International Security (ISIS) reported that it appeared to be operating, albeit not continuously and at reduced power.

In January 2016 DPRK evidently exploded a fourth nuclear device underground at or near Punggye-ri, claiming that it was a small hydrogen bomb.

In August 2016 the IAEA reported that the DPRK had unloaded fuel from the Yongbyon reactor and reprocessed it. In that case up to 8 kg of plutonium could have been added to its supplies. ISIS estimates that at the end of 2016 DPRK had somewhere in the range of 13 to 30 nuclear weapons. In September 2016 a fifth underground nuclear explosion was announced and detected at Punggye-ri, more powerful than previous ones, with a yield of about 10 kilotonnes TNT. In September 2017 a sixth such explosion occurred, evidently more powerful again.

Uranium enrichment, research reactor

In October 2002 it emerged that the DPRK had been working clandestinely to enrich uranium for weapons use, using centrifuge equipment. There appeared to be some linkage to Pakistan's centrifuge program and in 2005 Pakistan confirmed that its Khan network had supplied P2 centrifuges to the DPRK in the 1990s. The scope of this program remained unknown then, and in 2009 the official DPRK news agency announced that uranium enrichment tests had been carried out successfully and the process was in its final stage.

The question about uranium enrichment capacity was unresolved through these negotiations. In November 2010 it was confirmed that since 2008, some 2000 centrifuges had been set up in a building at Yongbyon, on the site of a fuel fabrication facility. The centrifuges appear to be Pakistani P2 types and their purpose is unknown, though North Korea says that they are producing only low-enriched uranium. Capacity was estimated at 8000 SWU/yr, capable of producing about 26 kg of weapons-grade uranium per year if applied to that end, but the capacity appears to have doubled to 16,000 SWU/yr in 2015. In January 2016 ISIS reported that the plant appeared to be operational. In May 2018 ISIS also identified Kangsong just south of Pyongyang as a suspect uranium enrichment site.

North Korea has a small research reactor supplied by Russia at Yongbyon, the IRT, producing radioisotopes. It started in 1965 as a 2 MWt unit but has been uprated to 8 MWt. Originally it was fuelled with 10% enriched uranium, but then went to 36% and finally 80% with the uprates. Russia stopped supplying enriched uranium for this in 1990, and the imported fuel was used by 2011, according to ISIS. Prior to that there was some discussion about converting it to run on near 20%-enriched fuel, and this may have happened. It could be running on indigenous enriched fuel, which would require about 1000 SWU/yr of enrichment capacity. It was under IAEA safeguards, but is no longer.

Along with this, construction of a 25-30 MWe experimental light water reactor (ELWR) at Yongbyon is reported to have begun in mid-2010, and to require fuel enriched to about 3.5%. Construction was well developed late in 2011, and apparently still incomplete in mid-2014. In January 2016 it appeared to be non-operational, and questions arose regarding what type of reactor it actually was.

In its September 2011 report, the IAEA notes that uranium hexafluoride found in a cylinder shipped to Libya by the Khan network in 2001 “very likely” originated in the DPRK. The IAEA assesses that this indicates that North Korea had an undeclared uranium conversion capability prior to 2001.

In March 2017 the Institute for Science and International Security (ISIS) said there were strong indications that North Korea had built and was operating a lithium-6 production plant at Hungnam Chemical Complex near Hamhung on the east coast. Li-6 is a critical raw material to produce tritium for thermonuclear weapons. It is produced by chemically enriching natural lithium to take the proportion from 7.59% to over 40%.

The IAEA Director-General said in March 2014: "It will be five years next month since Agency inspectors were asked to leave the DPRK. Nevertheless, the Agency maintains its readiness to play an essential role in verifying the DPRK's nuclear programme. I call upon the DPRK to comply fully with its obligations under relevant Security Council resolutions, to cooperate promptly with the Agency in implementing its NPT Safeguards Agreement, and to resolve all outstanding issues."

See also DPRK section of IAEA website.

Iran attracted world attention in 2002 when previously undeclared nuclear facilities became the subject of IAEA inquiry. On investigation, the IAEA found inconsistencies in Iran's declarations to the Agency and raised questions as to whether Iran was in violation of its 1974 safeguards agreement, as a signatory of the NPT, which it joined in 1970.

Bushehr reactor

Iran joined the NPT in 1974 and in 1975-76 construction started on two 1293 MWe nuclear reactors comprising the Bushehr power station on the Persian Gulf. Siemens KWU was the contractor. After the Islamic revolution, payment was withheld and work was abandoned early in 1979 with unit 1 substantially complete. About the same time, Iran purchased 450 tonnes of uranium (531 t U 3 O 8 ) from South Africa. Some 366 t of this was subsequently converted to UF 6 at Esfahan.

In 1994 Russia was brought in to complete unit 1 as a VVER-1000 reactor. This necessitated major changes, including fabrication of all the reactor components in Russia under a construction contract with Atomstroyexport. The reactor eventually started up in May 2011 and was grid-connected in September, with commercial operation in 2013.

All fuel for the life of the reactor is being supplied from Russia, and it is intended that used fuel will be returned there, obviating the need for any fuel cycle facilities in Iran. All work has been under IAEA safeguards and operation is also under safeguards. The Atomic Energy Organisation of Iran (AEOI) has announced that feasibility studies for a further 5000 MWe have been ordered.

The 6-7 TWh/yr output from the first reactor frees up about 1.6 million tonnes (11 million barrels) of oil per year for export (or c 1800 million m 3 of gas). In 2013 Iran’s Energy Minister said that it saved some $2 billion per year in oil and gas, so rapid payback of investment

Uranium enrichment

In connection with securing a supply of enriched fuel for its nuclear programme, in 1974 and 1977 Iran loaned $1.18 billion to the French Atomic Energy Commission to build the multinational Eurodif enrichment plant at Tricastin, and it took 10% equity in the enterprise (entitling it to 10% of output), which the Atomic Energy Organisation of Iran (AEOI) still holds. The loan was repaid with interest in 1991 but the plant has never delivered any enriched uranium to Iran. About 1991 Iran demanded delivery of its share of uranium under original contract, but this was refused by France due to political sanctions then being in force. Iran views this refusal as proof of the unreliability of outside nuclear supplies and uses the Eurodif episode to argue its case for achieving energy independence by supplying all of the elements of the nuclear fuel cycle itself. The 10.8 million SWU Eurodif plant operated by Areva started production in 1979 and closed in 2012. Iran has no equity in its successor.

In 2000 Iran declared its intention to build a uranium conversion plant (UCF) at the Esfahan Nuclear Technology Centre. At the same time it started building at Natanz a sophisticated enrichment plant, which it declared to IAEA after it was identified in 2002 by a dissident group. This is known as the Pilot Fuel Enrichment Plant (PFEP), but also at Natanz a large underground Fuel Enrichment Plant (FEP) was developed. Then traces of highly-enriched uranium were found at another facility connected with Natanz, the Kalaye Electric Co in Tehran. These traces were central to questions about Iran's compliance with its safeguards agreement. Questions about Iran’s intentions were further fuelled by discovery in 2009 of the underground Fordow Fuel Enrichment Plant (FFEP).

In 1991 Iran imported 1.8 tonnes of natural uranium from China. Iran did not declare this material however until 2002, and not all of it has been accounted for. Some was converted to metallic form – not required for any part of Iran's declared programme. The country has very small uranium reserves, apparently insufficient for any nuclear power programme.

Tehran Research Reactor

Iran has a 5 MW pool-type research reactor in Tehran which has operated since about 1967 and is monitored by the IAEA. Since being converted from 93% HEU about 1988 by Argentinian specialists, the Teheran Research Reactor (TRR) runs on 19.75% enriched uranium, and 116 kg of this was supplied from Argentina about 1993 - enough for 10-20 years depending on how the reactor is operated. This had nearly run out in 2009. The presence of molybdenum in Iranian UF 6 means that domestic supplies may be unsuitable at this level of enrichment, but this is unconfirmed.

In 2009 it seemed likely that Russia might provide some further uranium for TRR fuel blended down from 36% enriched material and fabricated in France, in exchange for an equivalent amount of its own (< 5%) enriched uranium from Natanz. This was rejected by Iran, which then tabled a revised proposal. At issue was the amount of Iran's uranium stockpile to be handed over at one time. The international negotiators wanted to do this exchange in one large shipment, while Iran preferred several smaller swaps which maintained more of its overall holding for a longer period. In February 2010 the government ordered the AEOI to commence enriching Iranian uranium to 19.75%.

IR-40 heavy water reactor

Iran is also developing a 40 MW heavy water-moderated "research" reactor at Arak fuelled by natural uranium. It is declared as being to replace the old Teheran reactor. The IR-40 design is very similar to those used by India and Israel to make plutonium for nuclear weapons. Construction is under way and the incomplete plant was "inaugurated" in August 2006.

In July 2011 AEOI reported it as 75% complete. Iran has said that it will be under IAEA safeguards, and it has been subject to IAEA inspection during construction. However, in August 2012 the IAEA noted that “the lack of up-to-date information on the IR-40 Reactor is now having an adverse impact on the Agency’s ability to effectively verify the design of the facility and to implement an effective safeguards approach.” No design information for the IR-40 reactor had been provided since 2006. At May 2015 the plant had not been completed. Following UN acceptance of the Joint Comprehensive Plan of Action in July 2015, the Chinese foreign minister announced that China had undertaken to modify the Arak reactor and that to effect this “a joint working group consisting of the six parties and co-chaired by China and the United States will be set up.”

A heavy water production plant is operating at Arak, but the IAEA was denied access to it until December 2013.

Fuel fabrication

A fuel manufacturing plant (FMP) has been constructed at Isfahan to serve the IR-40 reactor and potentially Bushehr. To May 2015, 36 prototype and 11 final natural uranium fuel assemblies for IR-40 had been produced here, totaling 102 tonnes. Two fuel assemblies using 3.4% enriched uranium of mass 6 tonnes had also been produced.

The Fuel Plate Fabrication Plant (FPFP) at Esfahan converts near 20% enriched UF6 to U3O8 and makes fuel assemblies for TRR from these. Over 30 such fuel assemblies had been made to May 2015.

All the above facilities, except the Kalaye plant and the Arak heavy water plant, are under IAEA safeguards. Details are in the Director-General's reports to the IAEA board on the IAEA website.

International pressure

As an expression of international concern about all these facilities apart from Bushehr, the IAEA gave Iran until the end of October 2003 to resolve outstanding questions about them and its materials. In "a welcome and positive development", Iran then formally told the IAEA that it would accept the Additional Protocol to its safeguards agreement with IAEA, and that it would suspend all enrichment-related and reprocessing activities in Iran, specifically those at Natanz. However, implementation of measures in accordance with the Additional Protocol was suspended early in 2006, and enrichment resumed.

An IAEA report released to its member states in November 2003 showed that Iran had, in a series of contraventions of its safeguards agreement over 22 years, systematically concealed its development of key techniques which are capable of use for nuclear weapons. In particular, that uranium enrichment and plutonium separation from spent fuel were carried out on a laboratory scale. Iran admitted to the activities but said they were trivial.

In June 2004 The IAEA Board criticised Iran for failing to cooperate adequately with IAEA investigations of its nuclear program. Something of a stand-off then ensued until in August 2005 Iran announced that it would continue its endeavours to enrich uranium, despite international attempts to dissuade it, and the 200 t/yr conversion plant at Isfahan was started. However, the uranium feed from Iran's mines has significant levels of molybdenum and other contaminants which create difficulties for any enrichment, and particularly so for high enrichment. Estimates varied widely regarding what was required to overcome these problems, and the IAEA reports make no mention of them.

In August 2005 the IAEA Board called upon Iran to suspend work associated with uranium enrichment. In March 2006 the IAEA referred the issue to the UN Security Council. However Iran has not backed off from its uranium enrichment.

A Joint Plan of Action to curb Iran’s evident progress towards nuclear weapons capability was initiated on 24 November 2013 between Iran and the foreign ministers of China, France, Germany, Russia, UK, and USA (P5+1 – the five permanent members of the UN Security Council plus Germany) and a senior EU representative. It linked closely to the IAEA Joint Statement on a Framework for Cooperation signed two weeks earlier, and over the next 16 months proved effective in rolling back Iran’s nuclear program for the first time in a decade, applying innovative inspections measures, allowing only modest sanctions relief and keeping substantial pressure on Iran.

Enrichment ramp-up

Since about 2000 Iran’s uranium enrichment work has increased. Operations at the PFEP, FEP and the UCF are under international safeguards, though monitoring is constrained.

The IAEA 2003 report said that while no evidence of a weapons program had been found, it could not conclude that Iran's nuclear program was exclusively for peaceful purposes. In April 2006 it said that after three years of investigation and requests for information, the existing gaps in knowledge of Iran's nuclear program continued to be a matter of concern. The required "transparency and active cooperation by Iran" to enable the IAEA "to understand fully the twenty years of undeclared nuclear activities by Iran" were not forthcoming.

In March 2007 the Russian government told Iran that it would indefinitely withhold fuel for the almost-complete Bushehr nuclear power reactor unless Iran suspended its uranium enrichment programme. Some Russian staff working on the project returned home. In the event, some 82 tonnes of fuel was delivered to Iran early in 2008. Fuel loading was expected late in 2009 but was deferred.

On 24 March 2007 the UN Security Council unanimously adopted a resolution imposing further sanctions on Iran and reaffirming that Iran must take the steps required by the IAEA Board, notably to suspend its uranium enrichment activities.

IAEA reports have described the situation through to 2015, and some details are in the information paper on Nuclear Power in Iran .

In June 2007 the IAEA Director General said: "Iran has not taken the steps called for by the Board nor responded to the demands of the Security Council. The facts on the ground indicate that Iran continues steadily to perfect its knowledge relevant to enrichment and to expand the capacity of its enrichment facility. Iran has also continued with the construction of its heavy water reactor at Arak. … This is taking place without the Agency being able to make any progress in its efforts to resolve outstanding issues relevant to the nature and scope of Iran´s nuclear programme, or being able to implement the Additional Protocol that would enable the verification of the absence of undeclared nuclear activities."

The Fordow site

In September 2009, when it learned that the matter was about to be exposed in the UN General Assembly, Iran told the IAEA that it was building another uranium enrichment plant, but gave no details. It is the Fordow plant, about 20 km north of Qom, in an underground tunnel complex on a military base. According to the Iranian 'Nuclear Archive' this was the Al Ghadir project being built by the military from about 2002 originally to produce weapons-grade uranium from LEU supplied by AEOI. As of 2009 this Fordow Fuel Enrichment Plant (FFEP) had been transferred to AEOI and was designed to have 16 cascades of about 3000 centrifuges. It was expected to be operational in 2011. The IAEA first inspected it late in October 2009. In February 2013 it had four IR-1 cascades (two sets in tandem) operating, each 174 machines, producing 19.75% enriched uranium at a rate of 10.25 kg/month. In October 2015 the tally was still 696 centrifuges in operation, but they were enriching only to 3.5%. Four further cascades had been installed and were ready, and there were a further eight cascades with equipment in place but not installed. In total FFEP produced 246 kg of 19.75% LEU hexafluoride from 1806 kg of 3.5% hexafluoride.

Clearly Iran played for time following the discovery in 2002 of its activities contravening its obligations under the NPT, and it developed its enrichment capacity to a high level meanwhile. The existence of the Fordow plant is particularly significant in that it would provide sufficient capacity to take a portion of the Natanz output of LEU up to weapons-grade.

The IAEA continued full involvement with Iran on nuclear safety issues, focused on Bushehr.

Enrichment to 20%, heightened concerns

The IAEA stated clearly in November 2007 that unless the Additional Protocol was ratified and in place it is not possible for the Agency to establish that undeclared nuclear materials and activities are absent. Its "knowledge about Iran's current nuclear program is diminishing." Meanwhile enrichment continued in defiance of UN Security Council resolutions.

The Iran situation has revived wider concerns about which countries should develop facilities with high proliferation significance – such as enrichment and reprocessing, even under safeguards, if there is no evident economic rationale. At some point in the future, such a country could give three months' notice of withdrawal from the NPT and reconfigure its facilities for weapons production. The USA asserts that Iran has been in fact developing just such a breakout capability.

This contention was supported in February 2010 when the government ordered the AEOI to commence enriching Iranian uranium to 19.75%, ostensibly for the Teheran Research Reactor (TRR), thereby significantly closing the gap between its normal low-enriched material and weapons-grade uranium. On 14 February 2010 about 1950 kg of low-enriched uranium (< 5%) from FEP was taken to PFEP, which would be enough for vastly more 19.8% enriched uranium than the TRR could conceivably use. AEOI has said that the TRR requires 1.5 kg of fresh fuel per month. International concern regarding the surge of activity in enrichment to about 20% U-235 is based on the fact that in terms of SWU (energy) input this is about 90% of the way to weapons-grade material, and thus would require only a small and possibly clandestine plant to bridge the gap.

At PFEP, two cascades are designated for production of LEU enriched up to 20% U-235, apparently for the TRR, and the balance of the plant is designated for R&D. One cascade enriches from 3.5% LEU to almost 20%, while the second one takes the tails from the first one and produces about 10% LEU with tails of less than 1% uranium. The enriched stream is fed into the first cascade. In total, some 1631 kg of 3.5% LEU from FEP was fed into one of these cascades, and 202 kg of 19.75% enriched uranium was produced at PFEP from the start of operations to January 2014 when enrichment to this level ceased under the Joint Plan of Action.

The IAEA earlier said that the PFEP operations now "required a full revision of the previous safeguards approach," including enhanced surveillance and checks. On 23 June 2011 the head of AEOI was quoted as saying: "We have the ability to produce 5 kg (of 20% enriched uranium) each month, but we do not rush." He had earlier said that the TRR required 1.5 kg of fuel per month. In August 2011 he confirmed that Iran had more 20% LEU than it needed for the Tehran research reactor, and that “security measures required that the sensitive part of the facilities would be transferred to underground buildings” – evidently Fordow. The IAEA reported then that monthly production rates of near 20 percent LEU had increased significantly, implying better performance of the two IR-1 cascades.

Over 2009-10 the Iranian centrifuge program was set back by the Stuxnet computer virus which affected Iranian companies involved with the control systems for the IR-1 centrifuges. In late 2009 to early 2010 about 1000 centrifuges at FEP were decommissioned. This appears to have been due to Stuxnet affecting frequency converters and causing the motors to over-speed, destroying the units. The normal failure rate of the IR-1 centrifuges is reported as about 10% per year.

The underground Fordow enrichment plant (FFEP) is evidently playing a larger role in producing 19.75% enriched uranium, using the well-proved IR-1 centrifuges. This positions Iran to stockpile a large amount of 19.75% LEU in a facility better protected against military strikes.

Between PFEP and FFEP Iran had produced 448 kg of 19.75% enriched uranium to January 2014, at over 15 kg/month. Of this, 337 kg (228 kgU) has been fed into conversion process at the Fuel Plate Fabrication Plant (FPFP) at Esfahan to produce 163 kgU as oxide (U3O8), and elsewhere 110 kg has been downblended to 5%. In May 2015 Iran had 228 kg of 19.75% enriched uranium, 61.5 kg as oxide powder, 44.9 kg as TRR fuel, and 121.2 kg as scrap, waste, or in-process, which created some concern for the IAEA.

In May 2014 the Enriched UO2 Powder Plant (EUPP) was commissioned. By May 2015, 6319 kg of natural UF6 (4262 kgU) had been converted to 1829 kgU as UO2, and 2720 kg UF6 enriched up to 5% (1835 kgU) had been converted to 151 kgU as UO2.

(Above paras are IAEA figures from May 2015 report, mass discrepancies unexplained.)

In June 2010 the AEOI announced that it planned to build four new research reactors for production of medical isotopes, including a 20 MW one to replace TRR when its operational life finishes in 15 years. This plan would justify production of more 20%-enriched uranium at Natanz, which gives rise to international concern.

Further concern was raised when Iran announced that it might build a nuclear-powered submarine, since this would potentially legitimize the country having high-enriched uranium for fuel. It was denounced internationally as simply an excuse for the production of weapons-grade uranium. The potential legitimacy arises from section 14 of the standard Comprehensive Safeguards Agreements signed by non-weapons states. This allows fuel for a “non-proscribed military activity” to evade safeguards.

International action from 2013

An agreement to curb Iran’s evident progress towards nuclear weapons capability was struck in November 2013 between Iran and the foreign ministers of China, France, Germany, Russia, UK, and USA (P5+1 – the five permanent members of the UN Security Council plus Germany) and a senior EU representative. It linked closely to the IAEA Joint Statement on a Framework for Cooperation signed two weeks earlier, and over the next 16 months proved effective in rolling back Iran’s nuclear programme for the first time in a decade, applying innovative inspections measures, allowing only modest sanctions relief and keeping substantial pressure on Iran.

In April 2015 a framework agreement was struck by the P5+1 group and Iran, taking forward the November 2013 interim Joint Plan of Action and forming the foundation upon which the final text of the Joint Comprehensive Plan of Action could be written by the end of June. It reflected the significant progress made in discussions between the P5+1, the European Union, and Iran, though it conferred some legitimacy to Iran’s enrichment programme.

In mid-July 2015 the Joint Comprehensive Plan of Action (JCPOA) with Iran was signed, after protracted negotiations. Iran agreed that over the next 15 years it will not enrich uranium above 3.67% and will reduce its stockpile of low-enriched uranium from 9000 to 300 kg of enriched uranium. Uranium research and development activities will only take place at Natanz, with much reduced number of centrifuges, while no enrichment will be carried out at the underground Fordow site. At Natanz, the number of installed centrifuges would be reduced from 19,500 to 6,100, only 5,000 of which will be spinning. All of them will be first-generation types: none of its more advanced models can be used for at least 10 years, and R&D into more efficient designs will have to be based on a plan submitted to the IAEA. In addition, Iran has agreed indefinitely not to build any new heavy water reactors or stockpile heavy water, and that the Arak reactor will be redesigned, with the original core being removed and destroyed. All used fuel will be shipped out of the country.

A separate agreement with the IAEA set out a path for “the clarification of past and present outstanding issues” regarding suspected nuclear weapons activities. Once the IAEA confirms that Iran has complied with its obligations under the international agreement, economic sanctions will progressively be lifted. The IAEA welcomed Iran's decision to implement the Additional Protocol to its Comprehensive Safeguards Agreement with the IAEA, allowing the intrusive monitoring required under the Joint Comprehensive Plan of Action (JCPOA).

In October the Iranian parliament approved a bill on the implementation of the JCPOA. Following this, all participants started to prepare for implementing their respective commitments, including lifting sanctions once the IAEA has verified that Iran had completed all its steps.

In mid-November 2015 the IAEA reported that a total of 4,112 IR-1 centrifuges and related infrastructure had been removed from service at the Natanz fuel enrichment plant along with 160 IR-2m centrifuges and related infrastructure. These centrifuges and other equipment are being stored at the site, under IAEA verification and monitoring. At the same time a total of 258 IR-1 centrifuges and related infrastructure were removed from the Fordow plant. In December 2015 Iran shipped more than 11 tonnes of various low-enriched uranium materials to Russia, in accordance with the JCPOA. The core of the Arak heavy water reactor was removed in January 2016 and concrete was poured into the calandria.

Implementation Day came in mid January-2016 when the IAEA verified that Iran had completed all of its nuclear commitments, the report of which was submitted to the IAEA Board and the UN Security Council. The effect of these actions is to increase Iran's 'breakout time' to obtain enough nuclear material for a weapon to one year, up from less than 90 days before the JCPOA. Iran must now start to implement provisionally the Additional Protocol to its IAEA safeguards agreement, which together with other measures under the JCPOA will increase the agency's ability to monitor nuclear activities in Iran and verify that they are peaceful.

See also WNA information paper on Iran , Iran section of the IAEA website , ISIS Nuclear Iran website , and Atomic Energy Organisation of Iran . Also IAEA media release July 2015 .

The main thrust of Iraq's uranium enrichment program to 1991 was the development of technology for electromagnetic isotope separation (EMIS) of indigenous uranium. This uses the same principles as a mass spectrometer (albeit on a much larger scale). Ions of uranium-238 and uranium-235 are separated because they describe arcs of different radii when they move through a magnetic field. This process was used in the Manhattan Project to make the highly enriched uranium used in the Hiroshima bomb, but was abandoned soon afterwards.

The Iraqis did the basic research work at their nuclear research establishment at Tuwaitha, near Baghdad, and were building two full-scale facilities at Tarmiya and Ash Sharqat, north of Baghdad. However, when the war broke out in 1990, only a few separators had been installed at Tarmiya, and none at Ash Sharqat. They had accumulated some 550 tonnes of uranium oxide concentrate which was finally removed from Tuwaitha in 2008 and sold to Cameco. At least half of this originated in Niger about 1981.

The Iraqis were also very interested in centrifuge enrichment, and had been able to acquire some components including some carbon-fibre rotors, which they were at an early stage of testing.

In 1990 Iraq was clearly in violation of its NPT and safeguards obligations, and the IAEA Board of Governors ruled to that effect. The UN Security Council then ordered the IAEA to remove, destroy or render harmless Iraq's nuclear weapons capability. This was done by mid-1998, but Iraq then ceased all cooperation with the UN, so the IAEA withdrew from this work.

In 1981 Iraq's 40 MWt Osirak nuclear reactor was destroyed by an Israeli air strike just before fuel was first loaded into it. It was a French light-water materials test reactor using high-enriched uranium fuel, and Israel alleged that its purpose or at least potential was military.

Iraq joined the NPT in 1969, and its safeguards agreement with the IAEA was concluded in 1972.

South Africa

Another case of developing nuclear weapons was not under the NPT. Here, the state concerned had a nuclear power program producing nearly 10% of the country's electricity, whereas Iraq and North Korea only had research reactors. In addition to a 300,000 SWU/yr uranium enrichment plant at Valindaba which was set up to serve its nuclear power program during a time of trade sanctions, South Africa had a small finishing plant at Pelindaba which took a small proportion of the output and enriched it to weapons-grade.

In 1991, South Africa acceded to the NPT, concluded a comprehensive safeguards agreement with the IAEA, and submitted a report on its nuclear material subject to safeguards. However, the IAEA's initial verification task was complicated by the country's announcement that between 1979 and 1989 it built and then dismantled a number of nuclear weapons. In 1977 it was preparing to test the mechanism of such weapons in the Kalahari Desert, but was dissuaded following joint Russian and US aerial surveillance of the site. The IAEA was asked by South Africa to verify the conclusion of its weapons program.

In 1995 the IAEA was able to declare that it was satisfied all materials were accounted for and the weapons program had been terminated and dismantled.

Israel is one of three significant countries which have never been part of the NPT. Unlike India and Pakistan , Israel has no civil nuclear power program. However, in 1975 it concluded a limited safeguards agreement with the IAEA.

After Israel was established in 1948, there was close collaboration between France and Israel in nuclear research. Israeli scientists were involved with early French facilities near Marcoule.

In 1952 the Israel Atomic Energy Commission was established, and in 1955 the USA agreed to supply a 5 MWt pool-type reactor for Nahal Soreq, south of Tel Aviv. This IRR-1 required high-enriched uranium supplied from the USA. It started up in 1960 and from the outset was required to be under IAEA safeguards.

In 1957 an agreement was signed with France to build a large (24 MW thermal) heavy water research reactor at Dimona in the Negev desert. This would run on natural uranium and incidentally be suitable for producing weapons-grade plutonium. France apparently supplied four tonnes of heavy water for the reactor and also assisted in the construction of a reprocessing plant at the site.

In 1960 France reportedly urged Israel to put Dimona under full international safeguards, but this was not done. Due to US pressure, cursory twice-yearly inspections were carried out of the reactor only. The reactor started up in 1964, and with the benefit of oversize cooling circuits, power was subsequently raised to 70 MWt. A full suite of infrastructure is reportedly at the Dimona site, including fuel fabrication.

Uranium for the reactor was initially sourced from indigenous deposits, but most is believed to have come from South Africa, over some 20 years of nuclear collaboration from 1967.

In 1968 the US Central Intelligence Agency concluded that Israel had started producing nuclear weapons from separated plutonium. In 1974 it appeared to have 20 nuclear bombs, and by the late 1990s the estimate had grown to 75-130 nuclear warheads. No tests have been undertaken in Israel, but it is widely believed that Israel collaborated with South Africa in a 1979 test off the east coast there.

Israel has never confirmed or denied that it has nuclear weapons.

Using conventional weapons, an Israeli Air Force strike in 1981 destroyed Iraq's Osirak nuclear research reactor near Baghdad.

From about 2001 to 2007 Syria constructed a graphite-moderated gas-cooled nuclear reactor at Dair Alzour, a remote site on the Euphrates River, near Al Kibar. It was very similar to the plutonium production reactor at Yongbyon in North Korea, using natural uranium and graphite moderator. It was about 25 MWt and next to the reactor cavity had vaults for heat exchangers and spent fuel pond, but no turbine generator. The uranium came from indigenous phosphate deposits as by-product of treatment at Homs (Syria produces over 3.5 Mt/yr of rock phosphate which could yield 100-200 tU/yr).

Before fuel was loaded it was damaged beyond repair by an Israeli air strike in September 2007 and the remains were demolished and buried soon after. The entire enterprise, apparently aimed at production of weapons plutonium, was clandestine and in breach of Syria's obligations under the NPT. The evidence also pointed to North Korean involvement in supplying nuclear equipment. Syria claims that the building was a military non-nuclear installation, but has declined to discuss the matter with the IAEA in the light of evidence to the contrary, or to account credibly for the presence of anthropogenic (industrially-treated) uranium found at the site by IAEA in June 2008. It has refused to allow further IAEA access to this site or to a facility near Marj as Sulţān located in the eastern suburbs of Damascus, which was apparently connected with fuel preparation.

In its November 2010 report, the IAEA said that Syria's cooperation with the Agency had diminished, access was still denied to several sites in question, and there were several serious questions and issues outstanding. The IAEA called on Syria to sign and fully implement an Additional Protocol - supposedly in force from 2006 – as well as urgently remedying its non-compliance with its existing NPT safeguards agreement, concluded in 1980. In June 2011 the IAEA board resolved to report Syria to the UN Security Council and General Assembly over non-compliance with its safeguard obligations and failing to declare the construction of a nuclear reactor.

After several months of negotiations, Libya agreed in December 2003 to halt its development of nuclear weapons. For more than a decade it had been engaged in the development of a uranium enrichment capability, based on importing natural uranium together with centrifuge and conversion equipment, and the construction of now-dismantled pilot-scale centrifuge facilities. Some of these activities should have been reported to the IAEA under Libya's 1980 Safeguards Agreement with the UN body, but were not.

Evidently Libya's nuclear enrichment program was at an early stage and no industrial-scale facility had been built, nor any enriched uranium produced. Pakistan, which is not a party to the Nuclear Non-Proliferation Treaty, was the source of the illicit technology from the late 1990s.

In its September 2011 report on North Korea, the IAEA notes that uranium hexafluoride found in a cylinder shipped to Libya by the Khan network in 2001 “very likely” originated in DPRK.

Libya has a Russian 10 MW research reactor using 80% enriched fuel, which has been under IAEA safeguards. It has no nuclear power program. It asked the IAEA to verify publicly that all of its nuclear activities will henceforth be under safeguards and exclusively for peaceful purposes. In that regard, Libya agreed to take the necessary steps to conclude an Additional Protocol to its NPT Safeguards Agreement, and this came into force in 2006. This will provide the IAEA with broader inspection rights, and will require full transparency and active co-operation. The first IAEA inspections of previously-undeclared facilities were at the end of December 2003.

Burma/Myanmar

There have been persistent reports from defectors, opposition and dissident groups regarding certain technical developments in Burma which may indicate a program to develop a nuclear weapon. These are unconfirmed, and Burma formerly refused to cooperate with IAEA in any investigation, despite its safeguards agreement with IAEA having been concluded in 1995. However, in June 2011 the vice-president said that Myanmar “has halted [its nuclear research] programme as [the] international community may misunderstand Myanmar over the issue.” He said, “Myanmar made arrangements for nuclear research with the assistance of Russia in order that Myanmar will not lag behind other countries in that field and to improve its education and health sectors…,” but “Myanmar is [in] no position to take account of nuclear weapons and does not have enough economic strength to do so.” This statement was followed by the announcement that Myanmar has halted its nuclear research due to the high potential for international confusion. Then in November 2012 it announced that it would sign the Additional Protocol, and did so in September 2013. In mid-2013 the president reiterated the 2011 commitment. Concern had centred on North Korean involvement.

Main Sources: Australian Safeguards & Non-proliferation Office, Euratom Bulletin of Atomic Scientists, March 2003, North Korea's nuclear program 2003 Bulletin of Atomic Scientists Sep-Oct 2002 David Albright and Christina Walrond, Institute for Science and International Security (ISIS), Iran's Gas Centrifuge program: Taking Stock (11 February 2010) David Albright and Christina Walrond, Institute for Science and International Security (ISIS), Technical Note: Revisiting Bomb Reactors in Burma and an Alleged Burmese Nuclear Weapons Program (11 April 2011) Institute for Science and International Security (ISIS), numerous posts especially on Iran . See also ISIS NuclearIran website

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John H. Perkins; Closing Diablo Canyon Nuclear Power Plant, 2009–2018: Decision-Making on Energy Investments Relevant to Climate Change. Case Studies in the Environment 31 December 2019; 3 (1): 1–11. doi: https://doi.org/10.1525/cse.2018.001313

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Modern economies cannot function without electricity, and production of electric power affects citizens in many ways, including climate change. Production of electricity requires investments that easily reach billions of dollars, and streams of investment capital must be perpetual to procure fuel, build and maintain plants, and transmit electricity to customers. This case study addresses whether a California decision relevant to investments about generating electricity adequately considered competing concerns. In 2009, Pacific Gas and Electric (PG&E, a private, investor-owned utility) applied to renew the operating licenses of its two nuclear reactors at the Diablo Canyon Nuclear Power Plant (the “plant”). By 2016, PG&E had decided not to seek license renewal and asked the California Public Utilities Commission (CPUC) to approve a price increase for its electricity to pay for specified expenses in closing the plant, which generated 24% of PG&E’s electricity. Four environmental groups and two labor organizations supported PG&E, and CPUC approved most elements of PG&E’s plan in 2018. PG&E’s application generated considerable debate during the CPUC process, and multiple organizations argued that PG&E’s plan was flawed. Two of the protests were from environmental groups favoring nuclear power as mitigation for climate change. Nuclear reactors generate electricity with uranium and have low emissions of carbon dioxide, the key source of climate change. This case study summarizes the competing arguments relevant to energy investments and climate change. Was the decision to close the plant in the best interest of the PG&E customers and the residents and taxpayers of California?

Recognize the key role of investment decisions in energy.

Recognize that decisions on investments in energy affect climate change.

Recognize competition among primary energy sources for generating electricity.

Recognize that institutional and regulatory structures affect competition among alternative primary energy sources.

In August 2016, Pacific Gas and Electric (PG&E) asked the California Public Utilities Commission (CPUC) to permit several actions. The requests most relevant to this case study were (a) to approve a schedule for closing the Diablo Canyon Nuclear Power Plant (“the plant”) and (b) permission to allow higher prices for electricity to pay for expenses associated with closing the plant.

The proposal was from PG&E, but the utility had, 1 month earlier, signed a “Joint Proposal” with four environmental groups—each of which opposed the use of uranium (nuclear power) to generate electricity—and two labor organizations—both of which represented PG&E employees. The plant had two nuclear reactors, unit 1 licensed to operate until 2024 and unit 2 until 2025.

The Joint Proposal was not filed as a legal document with CPUC, but it was included as an appendix to PG&E’s formal filing. PG&E had sought the six collaborators 1 to show broad support for PG&E’s requests [ 1 ].

CPUC granted some of PG&E’s requests in 2018, and at one level it was a routine exercise of CPUC’s regulatory powers over private utility companies and not necessarily of high interest in the environmental arena. Multiple contextual factors, however, made the exercise of distinct environmental importance.

Most important were the connections to climate change. Scientists broadly agree that carbon dioxide (CO 2 ) is the most important greenhouse gas introduced into the atmosphere by humans [ 2 ], and this gas is responsible for most of the temperature increases observed over the past century [ 3 ]. Climate change, in other words, has been triggered primarily by human additions of CO 2 to the atmosphere, and most of the CO 2 comes from burning fossil fuels (coal, oil, and gas). Electricity production is a major use of fossil fuels, but nuclear power plants using uranium emit much less CO 2 . As this case study will show, some environmental groups (other than the collaborators) argued against PG&E and closing the plant, because of its capacity to produce electricity with low CO 2 emissions.

Mitigation of climate change requires investments to enable electricity production without fossil fuels. Should some of the investments enable continued uses of uranium or not? This is a major question facing policy makers seeking mitigation of climate change, and no scientific or political consensus exists on the best answer.

PG&E in collaboration with its environmental allies claimed it could use renewable energy and energy efficiency to replace the electricity lost from closing the plant [ 4 ], a position consistent with extensive studies showing the enormous energy supplies potentially available from renewable sources (wind, solar, hydropower, biomass, and geothermal heat) [ 5 ]. As the case will show, however, other environmental critics [Environmental Progress and Californians for Green Nuclear Power (CGNP)] feared that the utility would instead use natural gas, a fossil fuel, and disrupt California’s efforts to curtail CO 2 emissions [ 6 ]. In the 1960s, environmental critics of the plant had objected to industrial development of pristine coastline and to pollution risks of using uranium [ 7 ]. In contrast, Environmental Progress and CGNP in this case refocused criticism to climate change and argued to continue operating the plant. Arguments among environmental groups and how they change are important, but they are not the focus of this case study. Instead, this case delves into CPUC’s effects on investment decisions underlying all supplies of energy.

Major investments undergird all energy projects, and CPUC’s authority indirectly affected a perennial question for PG&E: “What investments will the utility make to generate electricity?” If not uranium, then what energy source would PG&E use? CPUC does not directly control investments by regulated utility companies, but its regulations and decisions profoundly affect utility decision-making:

regulating electricity prices informs utilities of the likelihood of profiting from investments,

mandating adequate generation capacity to meet the demands of customers forces utilities to prepare for their customers’ needs, and

regulating compliance with California’s minimum requirements for renewable energy, with low emissions of CO 2 , forces utilities to select their energy sources accordingly.

Despite its profound indirect affects, CPUC does not dictate investment decisions to PG&E. PG&E determines how it will invest its funds, and its decisions stem from the need to recoup its investment expenditures by selling electricity at prices regulated by CPUC. PG&E must also consider its mandate to comply with other CPUC requirements: to have enough power to serve its customers and to comply with California laws on amounts of electricity sales from renewable energy sources. PG&E’s application already included plans for its legal obligations. In addition, the utility had undoubtedly considered the costs of NOT closing the plant, but these details are not visible to the public.

For its part, CPUC is bound by strict rules. It must make its decisions based solely on evidence presented in the hearings and legal briefs surrounding the requested rate increase [ 8 ]. Other parties may have had strong opinions that affected PG&E, but if that information did not enter the record, it could not be considered.

Consider a few of the other events or actions that may have shaped PG&E’s decision-making or the opinions of the public, but which never entered the record and thus were not eligible for consideration.

Natural gas in the USA has become relatively less expensive since 2009 due to the enhanced technology of hydraulic fracturing (“fracking”) that releases natural gas from previously inaccessible shale formations [ 9 ]. Many nuclear power plants are old and in need of relicensing and extensive upgrades, making them uneconomic to continue operating compared to gas and, increasingly, to renewable energy [ 10 ].

Federal subsidies for construction of new nuclear power plants, authorized in 2005, combined with utilities charging electric consumers for construction in progress have failed to ignite a “nuclear renaissance” building many new reactors. Three projects underway in 2016 demonstrated that nuclear power plant construction had never solved the economic problems leading to cessation of new construction in the late 1970s [ 11 ]. One of the projects, V. C. Summer in South Carolina, collapsed in bankruptcy in August 2017, with a loss of US$9 billion [ 12 ]. The second, Alvin W. Vogtle in Georgia, is still proceeding (2018), despite large cost overruns, delays, and projections of uneconomic performance when completed. Continuation required further financial contributions from customers, approved by state regulators [ 13 ]. The third, Watts Bar in Tennessee, began operating commercially in October 2016. It is the only one, so far, of the three new projects to reach completion, but critics have pointed to its antiquated design, no longer considered safe, and to its cost overruns [ 14 ].

On 11 March 2011, an earthquake and tsunami badly damaged Japan’s Fukushima-Daiichi nuclear power plant and led to catastrophic explosions in three of the plant’s six reactors [ 15 ]. This catastrophe led the U.S. Nuclear Regulatory Commission (NRC) to ask all nuclear power plants in the United States about the abilities of their respective plants to withstand earthquakes [ 16 ]. PG&E completed most of the required examination by 2015, but the issue of seismic safety of the Diablo Canyon plant had been contested since the 1980s and remained so in 2015 [ 17 ].

The new presidential administration elected in 2016 came in explicitly disavowing concern about CO 2 and climate change and enthusiastically seeking to revive the fortunes of coal power plants. The administration has also strongly downplayed concerns with pollution, and they added promotion of nuclear power plants to efforts with coal plants. This administration has consistently sought ways to subsidize the uses of both coal and uranium in plants that are nearing retirement and no longer viable economically [ 18 ].

This study focuses on the CPUC processes because they were one of the few instances allowing public participation in legal procedures that affected decision-making on investments by a private utility, especially as those decisions affect climate change.

The study asks readers to sort through competing arguments—entered into the record—about primary energy sources to decide, “For the purposes of lowering risks from climate change, was the decision to close the plant—and stop using uranium to make electricity—in the best interests of PG&E customers and the residents and tax-payers of California?” This case allows a unique glimpse of diverse opinions about decision-making involving investments, energy, and climate change.

The issues involved are complicated, and this study can only summarize them. Readers may want to consult outside materials to better understand the areas of contention. Suggestions for further reading are at the end.

PG&E is a private, investor-owned utility that generates, transmits, and distributes electricity to about 16 million California citizens scattered over 70,000 square miles [ 19 ]. PG&E manufactures some of the electric power from its own generators, and the plant ( Figure 1 ) produced 24% of PG&E’s electricity in 2016 [ 20 ]. The plant produced 7% of the total electricity retail sales in California in that year [ 21 ], and it was the last nuclear power plant operating in California. California also receives nuclear electric power from the Palo Verde nuclear power plant in Arizona. For example, the Los Angeles Department of Water and Power, a publicly owned utility, owns 5.7% of the Arizona plant and is entitled to draw as much as 9.7% of its output [ 22 ].

The Diablo Canyon Nuclear Power Plant located in California on the Pacific coast (Courtesy of John Lindsey, PG&E).

PG&E operates the plant under regulations of the U.S. NRC, which in the 1980s had issued two licenses, each for 40 years. License expiration was based on estimated lifetimes of the two nuclear reactors: 2024 (unit 1) and 2025 (unit 2). To continue operations after those dates, PG&E had to renew the two licenses, and in 2009, PG&E began the applications. This decision indicated that—in 2009—PG&E had decided to invest enough funds to meet NRC requirements. In 2005, a study on needed refurbishment or replacement of steam generators suggested that these costs could reach US$1 billion per reactor [ 23 ] or US$2 billion for both reactors at Diablo Canyon. Other costs could increase this total. As late as 25 February 2015, PG&E was still moving ahead with license renewal [ 24 ], but by 21 June 2016, PG&E had changed its mind [ 25 ]. Separately from the CPUC process, PG&E noted that as more renewable energy enters the transmission system between now and the plant’s retirement, the utility will lower the power output of the plant by about 50%. This will approximately double the cost of producing the plant’s electricity and diminish any competitive advantage it might have [ 26 ].

PG&E’s actions, both in 2009 and 2016, were major decisions about future investments: which fuels should the utility use to make electricity? Investment decisions are, in almost all cases, irrevocable choices of the fuel to be used. For example, a plant to use natural gas cannot use uranium, and a nuclear reactor using uranium cannot use coal. Similarly, a plant using solar radiation cannot use natural gas, coal, uranium, or wind.

Moreover, investments in energy must be perpetual, year after year, first to build the needed technology and then procure fuels. As equipment wears out, it requires further investments to maintain production. At the end of a machine’s lifetime, the company must invest to refurbish old or build new equipment, which means, “Same again or something different?” Failure to invest steadily ultimately ends electricity production.

Nuclear power plants use uranium as the primary energy source (fuel), and uranium is one of nine primary energy sources for making electricity. The other eight are coal, oil, gas, hydropower, solar radiation, wind, biomass, and geothermal heat. Energy efficiency can reduce the need for primary energy sources, but generating electric power means choosing among these nine fuels [ 27 ]. Currently, no other options exist.

A complicating factor in PG&E’s decision arose because of its location in San Luis Obispo County. The local economy had benefited economically for years from the plant. Dollars flowed into the county due to sales of electricity in other locations, and the wages of PG&E employees living in the area flowed in turn to local enterprises serving them. In addition, tax revenues from the employees and PG&E supported local governments and schools. Closure of the plant would disrupt the economic fortunes of thousands of employees, local businesses, and local governments [ 28 ].

PG&E is a highly regulated public utility, obliged to provide adequate, safe, and affordable electric power to its customers. In return for a quasi-monopoly status, PG&E may—with the approval of CPUC—charge rates to recoup and profit from its investments, including paying for the depreciation of the plant over time. CPUC approved parts of PG&E’s proposed plan on 11 January 2018 [ 29 ].

CPUC, a state agency with Commissioners appointed by the Governor, regulates companies providing electricity, natural gas (California’s major fuel for generating electricity and for other uses, Figure 2 [ 30 ]), telecommunications, passenger transportation, and water and sewer services. It also regulates the compliance of utility companies with California’s major laws to mitigate climate change by reducing emissions of greenhouse gases, such as CO 2 .

Primary energy sources used to generate electricity within California, 2001–2017. Graph shows (a) natural gas as the major fuel for California’s electricity, and (b) decline of nuclear power and rise of solar and wind power. Solar power exceeded in-state nuclear power for the first time in 2016. Solar power exceeded wind for the first time in 2015. (Courtesy of Michael Nyberg, California Energy Commission.)

CPUC decisions have powerful effects on investment decisions. Environmental Progress and CGNP argued against PG&E’s proposal, because these groups argued it was necessary to continue using uranium to generate power due to low emissions of CO 2 ; these protesters feared that electricity generated with natural gas would replace the plant’s electricity. Others, however, argued that moving away from uranium to some other primary energy sources was imperative, good, or at least acceptable.

CPUC’s process involves, sequentially:

the proposal from PG&E;

protests, responses, and motions to the proposal from other interested parties;

a reply to protests and responses from PG&E;

a prehearing conference and public participation hearings;

CPUC’s ruling on the scope of decisions to be made;

interested parties file briefs about the proposal based on scoping decisions;

CPUC issues proposed decision;

opportunity for written comments and final oral arguments about the proposed decision;

issuance of final decision; and

an opportunity to request a rehearing.

We turn first to PG&E’s proposal, then to arguments against the proposal based on preferences to relicense the plant, and finally the CPUC’s decisions on scoping and on its final decision.

PG&E’s and Its Environmental Collaborators’ Proposal

PG&E summarized four reasons for the reversal of its 2009 decision to relicense the plant, all based on uncertainty about the future [ 31 ]. Different people interpret uncertainty in different ways, and PG&E’s conclusions about the future may differ from others.

Uncertainty about the future amounts of electricity PG&E had to generate.

By law, PG&E had to maintain reliable sources of generation sufficient to serve its customers. Refurbishing the plant to pass NRC requirements for a renewed license—necessary to continue using uranium—might be expensive, as much as US$1 billion per reactor and perhaps more.

PG&E claimed its estimates of future demand for its electricity were uncertain because of new technology, such as LED light bulbs, enabled lower purchases of power. Also, its customers were installing solar panels and generating their own electricity.

Most importantly, changes in federal and California laws had enlarged the potential for competition in electrical markets. Starting in 2002, California allowed formation of Community Choice Aggregators (CCAs) that could purchase electricity from any generator and sell it over the transmission and distribution wires of PG&E. CCAs were public agencies operated as non-profit brokers of electricity. PG&E knew that many of its customers were likely to join a CCA [ 32 ] yielding a loss of sales and revenue, perhaps by half by 2025–2030 [ 33 ].

Mandated changes in California’s electric grid.

In 2002, California mandated electric generators to use renewable energy sources to generate 20% of their electric power, and this required-percent renewable increases to 50% by 2030. These regulations aimed to reduce emissions of CO 2 to mitigate climate change. PG&E had reached 33% renewables by 2016, over the target mandated for 2020 [ 34 ]. Uranium emits low levels of CO 2 but does not count toward the mandate [ 35 ].

PG&E claimed this evolution necessitated more flexible sources of generation, not met by nuclear power plants, which are used almost entirely for generating “baseload power,” i.e., the minimum amount of power used 24 hours a day. PG&E wanted generation technology capable of rapid increases or decreases of power during the day to meet “peak demand.”

A nuclear power plant might increase the cost of integrating renewable energy into the daily cycle of power demand.

California has excellent resources of solar radiation and wind, but these sources are (a) intermittent and (b) fluctuate up and down during each day. Solar radiation, for example, generates its maximum amount of electricity at mid-day, and grid managers are learning to accommodate solar fluctuations. PG&E claimed that the cost of integrating renewable energy into the power mix on the grid might be lower without the plant.

The plant faced uncertainty in regulation which could significantly increase operating costs.

PG&E claimed two specific examples of these potential uncertainties but did not provide details for the CPUC record. One, PG&E feared that the NRC might impose new safety requirements to obtain new licenses. PG&E had good reason, for example, to fear high expenses for seismic retrofits to renew the plant’s licenses. In 2013, Friends of the Earth (FOE), later one of PG&E’s collaborating environmental partners in 2016, had filed a lawsuit against the NRC for improperly handling PG&E’s existing licenses about the seismic safety of the plant [ 36 ]. In 2014, FOE had released a highly critical report of the plant’s seismic safety [ 37 ].

PG&E Responses and CPUC’s Scope of Issues Deemed Relevant

Two, the California State Water Resources Control Board had originally approved the plant’s operation with “once-through cooling” systems, i.e., water was pumped into the plant from the ocean, cooled the reactors, and discharged back into the ocean at a higher temperature. In 2010, however, the Board developed a new policy calling for “closed-cycle, evaporative cooling” or a reduction in damage to marine life due to cooling water intake. By 2016, when PG&E and its collaborators filed their proposal to CPUC, the utility still did not know the outcome of the Board’s decision. The Board was working collaboratively with other state agencies to manage both water quality and electric reliability and did not reach a final decision until 2018 [ 38 ]. Thus in 2016, PG&E had reason to fear high expenses to change the plant’s cooling systems to continue operating.

Responses of Opponents Relevant to Use of Uranium

Many parties responded to different issues in PG&E’s proposal, and two environmental groups—not part of the Joint Proposal—called for PG&E to continue using uranium indefinitely: Environmental Progress and CGNP. Both argued that nuclear power plants with low CO 2 emissions were essential to mitigate the risks of climate change. As with PG&E’s proposal, different people may reach different conclusions based on differences in weighing evidence and uncertainty about the future.

CGNP participated throughout the entire proceedings, was disappointed in CPUC’s approval of PG&E’s plan, and petitioned the Commission to rehear the case. The organization’s mission statement emphasizes the promotion of nuclear power as a source of carbon-free electricity [ 39 ].

Environmental Progress participated in the proceedings only at the beginning before dropping out. This organization, however, has a broader environmental mission: to lift all people out of poverty and to save the natural environment. Its president, Michael Shellenberger, has written widely on a variety of environmental issues and appeared in various public presentations, both in person and in film or TV. Shellenberger has become one of a handful of environmentalists advocating a comprehensive program for nuclear power and claimed credit for actions to keep other nuclear plants open in other states [ 40 ]. In 2018, Shellenberger ran unsuccessfully in the Democratic primary as a candidate for governor in California. The claims of Environmental Progress in this case rested on 10 points [ 41 ]:

California needed to increase the rate of its reduction of CO 2 by seven times, compared with the reduction rates of 2000–2014.

Despite the need to increase rates of reduction, emissions had been rising since 2011.

California’s population will rise between now and 2030, thus increasing emissions of CO 2 significantly.

If energy efficiency increases, electricity rates will increase, but overall electricity demand will still not fall.

To achieve California’s climate goals requires significant electrification of transport, and electric cars will consume additional amounts of electricity.

Closing Diablo Canyon will not allow use of a significant amount of solar “overgeneration” currently unused.

The plant’s low-carbon electricity will be replaced largely by fossil fuels, with additional emissions of CO 2 .

More use of natural gas in California to generate electricity will likely increase deaths from pollution and pipeline explosions. (A PG&E gas pipeline exploded in 2010, with 10 deaths and 38 homes destroyed in San Bruno, CA; faulty PG&E procedures were the cause.)

PG&E falsely claimed that very expensive reworking of the plants cooling systems will be required by California regulators.

Even with overestimated future costs, the plant will still produce cheaper electricity than other low-carbon sources.

PG&E Responses to Protests and CPUC’s Scope of Issues Declared Relevant

PG&E denied Environmental Progress’ claim that PG&E had “‘falsely’ stated” the costs that might be associated with revamping the plant’s cooling system. PG&E maintained that it was correct to worry about this issue, because the state agency responsible had not yet acted [ 42 ]. (Debate had surrounded the costs associated with a new cooling system [ 43 ], and a recent assessment by the California Energy Commission described the agreement PG&E was negotiating with the Water Board to pay mitigation costs for its cooling system until the plant closes [ 44 ].)

The Commission included two of Environmental Progress’ protests within the scope. First, the dates PG&E had proposed for closing the plant could be challenged [ 45 ]. Some parties argued for earlier closure, but Environmental Progress and CGNP argued for indefinite delay in closure, an argument to keep using uranium as an energy source.

Second, the scoping decision allowed challenges about the proposed replacement of power lost by closure [ 46 ]. PG&E had argued that it would use renewable energy and energy efficiency, claims that Environmental Progress found incredible. Environmental Progress, however, dropped its participation in CPUC’s process before its conclusion, and the organization has not published an explanation for its departure.

CPUC’s Decision

The CPUC’s final decision stated (a) PG&E could close the plant in 2024 and 2025, and (b) PG&E could increase prices of electricity to recover US$222.6 million to retain and retrain employees for closing activities and US$18.6 million for costs the utility had incurred for its initial activities to renew the plant’s licenses. Replacement of power lost was routed into the normal process of Integrated Resource Planning, an established process already in existence [ 47 ]. This planning framework covered all electricity procurement policies governed by CPUC, especially those related to meeting California’s goals for reducing emissions of CO 2 . It involved looking ahead 10 years, ensuring that local needs were met, and remaining flexible about the resources needed [ 48 ].

The Commission ruled against Environmental Progress’ recommendations to continue using uranium. By its actions, therefore, CPUC showed no evidence that it thought PG&E’s investment plans threatened the ability of the utility to continue providing power to its customers and to continue meeting its mandates for using renewable energy. In other words, CPUC saw no reason to recommend a change in PG&E’s decision-making on investments in energy or program to comply with California’s efforts to mitigate climate change.

Nuclear power and climate change have occupied a prominent place in public debates about environmental and economic policies for many decades. A strong regulatory framework created by comprehensive laws surrounds nuclear power and the use of uranium as an energy source, and the federal government dominates through the actions of the NRC. Without an NRC license, no one can build or operate a nuclear power plant. NRC, however, has no mandate to consider climate change. States and local governments have limited authority over nuclear power, confined largely to governing sites for plants and protection of other resources, such as water.

Climate change, in contrast, does not have a strong regulatory framework. The Obama Administration used the Clean Air Act and international agreements to move the United States toward concerted actions on climate change, but the Trump Administration has worked to reverse all these steps. No comprehensive law governing climate change permits robust actions by the federal government. State and local governments’ actions to protect air from polluting CO 2 are governed largely by federal laws that do not specifically target CO 2 and other greenhouse gases to protect the climate.

The question of nuclear power as a mitigating technology for climate change, therefore, falls between the cracks of federal laws, and state and local governments have a limited ability to deal with this issue. CPUC’s wrestling with the closure of Diablo Canyon made the gap between nuclear power and mitigation of climate change glaringly obvious. Neither PG&E nor CPUC had a mandate to consider climate change, other than CPUC’s mandate to enforce requirements for renewable energy. PG&E’s environmental partners had a clear interest in climate change, as did Environmental Progress and CGNP. The latter two groups, however, opposed closing the plant. Accordingly, the stage set by the CPUC process served as a poor arena for a fully rational discussion of nuclear power and climate change.

Flawed as the CPUC process may have been, very few alternatives, legal arenas exist for debates about nuclear power and climate change. This case study summarizes the major points made in the legal record—the only evidence that counted in CPUC’s process—and approved closure of the plant plus allowed PG&E to recover some costs associated with closure. If rule of law is to operate on climate change, however, legal stages are essential. Readers of this case should now consider and debate the issues illuminated and decide for themselves about the merits of CPUC’s decisions.

Did the issues PG&E provided for closing Diablo Canyon Nuclear Power Plant overlap with the issues raised by Environmental Progress? Explain any differences you see.

Explain in your own words how this case illustrates competition among fuels for making electricity. What role does CPUC play in these processes?

Do you think Environmental Progress gave careful attention to issues of costs to continue using Diablo Canyon Nuclear Power Plant?

Opponents of nuclear power have focused on issues, such as (a) political stalemate on proposals to dispose of nuclear wastes, (b) low-level radiation emitted normally by nuclear power, and (c) the potential for catastrophic accidents releasing large amounts of radiation. PG&E, Environmental Progress, and CGNP did not mention these other issues. CPUC did not have jurisdiction to consider them, because they are controlled by NRC. Should rate-setting by CPUC include them? Do these issues affect how you understand the relationship between nuclear power and climate change?

Explain in your own words how investment decisions affect the ways in which society generates electricity.

Many commentators have recently discussed the growing inequality of income and wealth in the United States, and government policies can substantially reduce these inequities. Concerns about environmental justice also point to the need for equity in bearing costs and risks. The Commission allowed PG&E to increase rates to recover US$18.6 million that the utility spent when it had intended to renew the licenses for the plant, and these costs will be paid by PG&E customers. Who should pay this cost: current customers, taxpayers, or utility stockholders? Justify your answer.

Similar to question 6, the Commission allowed PG&E to increase rates to recover US$222.6 million for retraining and retaining of employees of the plant, to be paid by PG&E customers. Who should pay these costs? Current customers? Stockholders of the utility? Let employees take care of their own futures, without financial assistance? Justify your answer.

Does this case study help you decide what you think about using uranium to generate electricity? Why or why not? Consider costs, equity, climate change, and the risks of pollution from different energy sources.

Did the CPUC reach a decision in the best interests of residents, rate-payers, and taxpayers of California? Why or why not?

What additional information do you want to answer any of these questions? Where might you find this needed information?

JP designed and wrote this case study.

Ralph Murphy and Tom Womeldorff provided excellent advice on a draft of this case study, and Dr. Murphy tested a draft in class. I am grateful to the students working with Dr. Murphy for their useful assessments of the case study, which led to further revisions. John Lindsey of PG&E provided the image of the plant ( Figure 1 ). Michael Nyberg of the California Energy Commission provided Figure 2 . Three reviewers of the manuscript offered valuable critiques and suggestions, for which I am grateful. I, however, remain responsible for any errors or muddled explanations.

No external funds were received to prepare this case study.

The author has no competing or conflicting interests of a financial nature. He was a customer of PG&E, but he recently elected to switch to Marin Clean Energy, a CCA. He also elected to pay slightly higher costs to have 100% of his home’s electricity supplied by renewable energy sources.

Supporting and additional information. Docx.

Primary data used in this case study can be retrieved from the websites of CPUC, other agencies, and NGOs.

The proposal was joined with four environmental groups opposed to continued operations of the plant (Natural Resources Defense Council, Friends of the Earth, Environment California, and the Alliance for Nuclear Responsibility) and two labor groups (International Brotherhood of Electrical Workers Local 1245 and the California Coalition of Utility Employees), both of which represented PG&E employees.

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Closure of nuclear plant sparks debate as new problem arises: 'It's been a real step backward'

T he 2017 decision by New York energy officials to begin closing the Indian Point nuclear power plant couldn't have been an easy one to make, but it was initially perceived as a win for the environment. Now, the fallout of the decision is raising new questions. 

What happened?  

By shuttering the facility, officials eliminated an installation with a growing amount of risky incidents, according to published reports , per the Guardian. The move also provided an opportunity for the state's renewable commitments to shine. 

However, the nuclear powerhouse had been generating air pollution-free energy since the 1960s, serving as one of the state's 10 largest electricity makers, according to the federal government.   

But natural gas has surpassed the wind and sun in replacing the fission reactor's generation in the Empire State, per a J.P. Morgan report. 

"From a climate change point of view it's been a real step backward and made it harder for New York City to decarbonize its electricity supply than it could've been," Ben Furnas, an energy policy expert at Cornell, told the Guardian. 

Indian Point was completely closed in 2021. The country now has 54 nuclear power plants, making about 19% of the nation's electricity. 

Watch now: Alex Honnold test drives his new Rivian

The shuttering came after repeated reports of calamity-capable mishaps, including transformer fires, radioactive spills, and failed accident drills, the Natural Resources Defense Council reports . United States Senator Bernie Sanders called the facility a "catastrophe waiting to happen," according to the Guardian. 

When the two newer reactors at the facility were cooking at the same time (the first of the three was closed in 1974), they met about a quarter of New York City's massive power needs. 

Why is the plant's closure important?

NYC's air pollution has gone up since Indian Point closed because dirty energy , not renewable sources, has mostly filled the gap.  

J.P. Morgan reports that three new natural gas plants and dirty energy imported from other states are keeping the lights on. As a result, NYC's regional emissions per megawatt-hour are higher than the nation's average — even more than ERCOT's , the agency responsible for managing most of the power supply in Texas. 

"So, while Texas is more 'red' than New York City, it's now more 'green' as well," the J.P. Morgan report, released in March, states . 

New York has ambitious sustainable energy goals, including reaching a 70% renewable power supply by 2030. In 2022, renewable and nuclear power accounted for 51% of "total in-state generation," according to the U.S. Energy Administration. 

"This has been a cautionary tale that has left New York in a really challenging spot," Furnas told the Guardian.

What can be done to help? 

Staying educated about renewable power projects is a good way to start. Technology to harness energy from the sun, wind, and waves is becoming more efficient and less expensive.

Community solar programs utilize the sun's power without installing a panel system. With some research online, you can save cash each year and prevent thousands of pounds of air pollution from hitting the atmosphere. 

Nuclear fusion advancements could eventually change the energy game entirely, providing a safer, less radioactive, and more abundant energy source. The tech could eliminate many of the fears about rare yet serious nuclear disasters , making tough decisions like the one regarding Indian Point a thing of the past. 

In New York City, officials plan to bring in hydropower from Canada and electricity from solar and wind upstate. Offshore wind projects in the works should help to increase the renewable output in coming years, too, per the Guardian. 

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Closure of nuclear plant sparks debate as new problem arises: 'It's been a real step backward' first appeared on The Cool Down .