During the COVID-19 pandemic, I completed a book on nuclear power market failure.

Market Failure – Market-Based Electricity is Killing Nuclear Power, was released in January 2021.

The book includes information on the nuclear power and electricity industries, market failure in the nuclear power industry, and some ideas about resolving this market failure.

The ideas in this book were developed in client engagements, published articles, presentations, discussions with industry experts, and Nuclear Economics Consulting Group (NECG) Commentaries.  NECG’s Affiliated Experts and other colleagues provided helpful comments and suggestions on the concepts in this book.  Jamie Boucher helped me understand how those outside the nuclear power industry view this book’s concepts.

Any errors or oversights in this book are mine.  Please send any comments, suggestions, or other ideas related to this book to: marketfailure (at) nuclear-economics (dot) com.

The post #32 – Market Failure – the Book appeared first on Nuclear Economics Consulting Group.

Nuclear power in the United States is struggling, with well-maintained plants closing early and few new projects in the works.  At the heart of these struggles lies a failed gamble: regulators and policy makers bet that market forces in de-regulated electricity markets would lead to the electricity sector that best served the needs of society.

Sadly, deregulated electricity markets have fallen well short of this target.  When markets fail, economic theory recommends prudent regulation. Instead, we have US energy subsidy policy, a poor replacement.

The Logic of Energy Subsidies

Energy subsidies are intended to steer markets away from a course considered bad for society. During the early years of a technology’s commercialization, subsidies are often used to increase investment and development, as well as to protect nascent industries from competition. Starting in the Carter administration with the creation of the Department of Energy, support for alternative fuel, and later renewable energy, often had this second goal in mind. Any technology that could diminish US reliance on imported oil had value, over and above its costs to consumers. It was in the best interests of the US to support these industries and help them develop.[1]

Proponents of renewable subsidies often present a cut-and-dried case of resolving market failure: Renewables provide clean energy, but the extra benefit that renewables provide (very low greenhouse gas emissions) is never incorporated into the market price of electricity, making renewable projects less profitable than they should be.

US federal and state governments step in, providing investment tax credits, production tax credits, feed-in tariffs, renewable portfolio standards, and other subsidies to address this market failure.  Such subsidies to renewable energy projects drive investment in these projects; indeed, renewable energy has seen significant growth over the period of subsidization, with increasingly competitive renewable generation costs compared to conventional energy sources.  Renewable energy subsidies seem to have delivered.

Problems with Energy Subsidies

Dig deeper, however, and there are significant problems with these subsidy programs, many of which become clear when the impact on nuclear power is considered.  In brief, US energy subsidy policy is inefficient, misguided, and often downright harmful.

Take first the aims of energy subsidization.  US government support for renewables is often framed as an effort to reduce greenhouse gas (GHG) emissions, but it does so poorly, if at all.

The goals of renewable subsidy are narrow, and unhelpful: they aim to shortsightedly maximize renewable construction.  Counter-intuitively, this often hinders the proper target of reducing emissions, largely because of the intermittency problem of many renewables: they’re not predictable or all-day power sources, so no matter how many wind farms and solar stations are built, the grid will still rely on base load generators.  Too often, these take the form of fossil fuel plants, given the market’s failure to deliver sufficient nuclear capacity and technological barriers to large-scale energy storage.  Subsidies fail to resolve underlying market failures, and so narrowly favor one piece of the zero-carbon puzzle (renewables) while leaving another (nuclear) to wither.

Researchers writing in Energy Economics[2] find purely economic arguments (though possibly not political ones) favor narrowing the policy space significantly: grant-based subsidies that are paid based on physical outcomes upon completion of a project can best leverage the interaction between government and market to maximize environmental outcome for government subsidies.

However, solar investment tax credits and federal loan guarantees have led to solar energy projects that failed to deliver the expected output, including the Ivanpah project, pictured above.  These federal solar incentive programs, coupled with California state renewable energy incentives, led to a boom in solar power generation in California linked to recent blackouts.

On the pollution front, the US government’s left hand doesn’t know what the right hand is doing.  Current federal subsidies to fossil fuels run to $20 billion a year, according to the Environmental and Energy Study Institute,[3] including around $4 billion for heavily polluting coal industries.  Energy subsidies have always been more focused on safeguarding energy security and entrenched economic agents than reducing harmful pollution.

Energy subsidies can also distort electricity market outcomes.  Some forms of quantity-based renewable subsidies, like production tax credits (mainly for wind) and feed-in tariffs can increase the effective revenue earned from renewable project output.  This, coupled with the design of electricity spot markets, results in distortions to market prices.  Generators bid into electricity markets with the price they are willing to accept, and bids are accepted from lowest to highest, with every generator being paid the value of the last bid accepted (the spot price).

Renewable generators often have incentive to bid negative prices: paying electricity markets to take their power.  This counter-intuitive outcome is the result of production-tied subsidies that are paid to generators only when they operate.  The net effect of such subsidies is to put downward pressure on the spot price, squeezing all producers.  Renewable producers benefit from this situation, as evidenced by strong investment in new renewable projects.  Renewable subsidy schemes are delivering their goal, but the unintended consequences can be severe.

Collateral Damage

A significant problem with current renewable subsidies is the harm they deal to other producers.  Nuclear power plants operating in electricity markets, for instance, are economically sensitive to spot prices, on which they depend to cover their fixed costs.  When prices fall below break-even, nuclear plants lose money.  The typical response of owners is to close nuclear power plants to stop financial losses (e.g. Kewaunee and Vermont Yankee).[4]  US nuclear power plants, once closed, have no path to re-start later, even when the physical plant could safely operate for decades more.  Downward pressure on spot prices, like that caused by quantity-tied renewable subsidies, can be fatal for nuclear plants.

This should be worrying.  A nuclear power plant is a valuable physical asset, a provider of high-quality jobs, a reliable source of generation capacity, and a significant provider of emissions-free electricity.  Nuclear power can go toe to toe with wind and solar for lifetime GHG emissions, as well as providing reliable output that intermittent renewables cannot.  Reactors provide baseload electricity, operating with capacity factors above 90%, rain or shine, wind or calm.

Practically speaking, this means that when a nuclear plant closes, its generation isn’t replaced by renewables; it simply can’t be.  Instead, displaced nuclear generation is replaced by the cheapest available reliable generating technology: carbon-emitting natural gas.  Thus, whenever a nuclear plant closes, GHG emissions go up.

A Better Way

There are known solutions to the problems created by US renewable subsidies.  While the challenges facing nuclear power are not wholly reducible to errors of subsidy policy, the fact remains that current subsidy design is inefficient and sometimes explicitly harmful to the goal of reducing GHG emissions.

Federal and state governments should undertake a systemic review of renewable subsidies, focused on developing subsidies that reduce total electricity sector GHG emissions, rather than the blinkered goal of simply getting more renewable projects built.  Then, the federal government should phase out subsidies for fossil fuels; earmarking these funds for financing a national nuclear build program would be a step forward.

Crucially, that will mean a harmonious set of overlapping and mutually reinforcing programs that are non-distorting, technology-specific, long lasting, and predictable.  Long-term predictable subsidies are especially important for nuclear power, where projects operate for many decades.

A key part of this approach should be a price on GHG emissions nation-wide, through a carbon tax or an emissions trading scheme.  Such a policy could effectively internalize the negative externalities that have been benefiting fossil fuels for as long as energy has been priced, to the benefit of nuclear and renewable generators and to society at large.

High Time for Change

It is well past time to re-think US federal energy subsidy policy.  The federal government seems to have no clear goal, and the market approach currently in effect is failing to deliver the best for society.  Government action is needed to resolve this failure, but it must be the right action.  Current subsidy policy is falling short.

This NECG Commentary was written by James Boucher.[5]

[1]           Mona L. Hymel and Beth S. Wolfsong, “Americans and their “Wheels”: A Tax Policy for Sustainable Mobility,” Arizona Legal Studies, Discussion Paper 06-15, (2006).

[2]          Richard G. Newell, William A. Pizer, and Daniel Raimi, “US federal government subsidies for clean energy: Design choices and implications,” Energy Economics, Vol. 8, (May, 2019).

[3]         Clayton Coleman and Emma Dietz, “Fact Sheet: Fossil Fuel Subsidies: A Closer Look at Tax Breaks and Societal Cost,” Environmental and Energy Studies Institute, (July 29, 2019).

[4]          See NECG Commentary #27.

[5]          James Boucher is an NECG Associate that is completing coursework at the London School of Economics.

PDF version

The post #31 – Time to rethink renewable subsidies appeared first on Nuclear Economics Consulting Group.

• Summary
• Background
• RAB Model Discussion
• Conclusions

I.   Summary

The challenges of delivering new nuclear power plant (NPP) investment in the reformed electricity industry in Great Britain are significant and there is no simple or easy approach to resolve those challenges.

The RAB model may be a useful tool if properly developed and implemented, but:

• Is complex and may be difficult to implement;
• May not clearly reflect the objectives for the British nuclear power industry;
• May not be relevant without a broader review and/or re-opening of the overall approach to the electricity industry structure and electricity market approach in Great Britain; and
• May not deliver desired new NPP investment, or may only deliver new NPP investment with EdF and/or other State-Owned Enterprises (SOEs), such as CGN from China.

We provide a response to the Consultation questions, as context for later sections of this Commentary that describe some issues that must be addressed to attract new NPP investment.

Question 1: Have we identified a model which could raise capital to build a new nuclear power station and deliver value for money for consumers and taxpayers?

Question 2: Do you have any comments on the components of the Economic Regulatory Regime as described?

Question 5: Do you have views on the potential way to design the revenue stream for a nuclear RAB model that we describe, and are there alternative models we should consider?

Question 6: Do you have views on our proposed approach to assessing a new nuclear project under a nuclear RAB model and determining whether it is value for money for consumers and taxpayers?

These four questions (i.e., 1, 2, 5, and 6) assume that the proposed RAB model is a complete and feasible approach that can be implemented in Great Britain to deliver enough new NPP capacity to close the “nuclear gap”.  We disagree and, as discussed in later sections, provide some questions and issues that must be answered and resolved before these questions can be answered.

Question 3: Do you have views on how consumer interests are protected under the proposed approach? What else should be considered to protect consumer interests?

There are some features of the proposed RAB model that may, in theory, protect consumer interests, but we are concerned that the proposed RAB model may not do so in practice.  The investment in developing and implementing the proposed RAB model will nevertheless be significant, even if it does not deliver the desired level and type of new NPP investment.

Question 4: Do you agree that consumer risk sharing could be value for money for consumers if it achieves a lower expected overall cost for consumers compared to a Contract for Difference model?

In theory, the answer is yes.  However, the question assumes that both models can deliver new NPP investment, which may not be true.  The incentive package in place for Hinkley Point C (i.e., the Contract for Difference / CfD model in this question) was not successful in delivering new NPP investment by Horizon, NuGeneration, or other developers/projects.  As discussed below, we are concerned that the proposed RAB model may not deliver new NPP investment without modifications and without other support measures.

II.   Background

Great Britain needs new nuclear power capacity to meet long-term policy goals related to carbon emissions and system reliability.  Nuclear power is a proven, large-scale, dispatchable generation technology with load-following capability, minimal carbon emissions, a fuel cycle supporting national energy security, a small environmental footprint, high energy density, and long asset operating life.

The approach to new NPP investment in Great Britain is to facilitate and provide incentives for investment from the private sector, including foreign State-owned Enterprises (SOEs).

The nuclear SOEs, such as those behind the HPC project, have risk preferences, access to national resources, and other features that are very different from private developers and investors seeking to develop new NPPs.  The CfD approach used in the HPC project was primarily focused on resolving project risk through post-completion revenue level and certainty, with completion risk absorbed by the foreign SOEs and their governments. If Great Britain is satisfied with new NPP projects negotiated in this political context, RAB may indeed provide an adequate basis to deliver new NPP investment, potentially[1] more favourable for NPP developers than the CfD approach due to more risk being absorbed by the British public.

In an ideal world, the outcomes of the electricity markets would provide incentives for new investment in nuclear power.  In the real world, liberalized electricity markets, do not provide adequate financial incentives for new generation investment in high-capital-cost generation assets, like NPPs, without out-of-market subsidies to provide adequate and certain long-term revenue.

This is due to at least four reasons:

• Liberalized electricity markets have short-term prices that may be too low and too uncertain to support new NPP investment;
• Little recognized or realized value in electricity markets for the public goods provided by NPPs (e.g., emission-free electricity, energy security, energy diversity);
• The long asset life of modern reactor designs (licensed for 60 years; possible life extensions to up to 100 years) are not captured by financial models, which fail to assess asset values after roughly 30 years; and
• New NPP investments, with high capital-intensity and long NPP operating life, may not be “bankable.” Financial markets do not treat private investment in NPP projects favourably, so that new NPP investment requires additional financial support and risk reduction measures.

British government (“Government”) measures to address these challenges in Great Britain to date have worked to a degree, but have not resulted in new NPP investment needed to close the nuclear gap.

New NPP project challenges include the large size and duration of the investment; a long and uncertain development and construction period; an unfavourable new build track-record; the complexity, cost, tenor, and uncertainty of nuclear safety regulation; and uncertain revenue after commercial operation.  NPP completion risk includes delays, cost-overruns, and the possibility of abandonment prior to completion.  NPP project returns, even with enhanced revenue after the start of commercial operations, may not be adequate to compensate investors for overall project risk.

The RAB model strives to address these challenges, but will require a large, complex process to develop and agree arrangements that satisfy all parties involved and protect the public interest.  A new regulatory body must be established undertake the critical tasks of monitoring and managing the RAB model.

Depending on the details and implementation of the RAB model, a regulated NPP developer/owner could get a fair return on and of its NPP capital investment and get recovery of NPP generating costs.  The ratepayers (i.e. customers of the regulated utility) could bear completion risk within agreed parameters.[2]

However, addressing the risk of cost overruns and project cancellation would be extremely challenging.  If coverage of this risk is not provided for NPP developers and their supply chain, then the fundamental problem is not resolved. If coverage of this risk is included with few limitations, the public could be at risk for because of incompetent or negligent NPP project developers.

III.   RAB Model Discussion

As a general matter, we see the RAB model as a way for the Government to address NPP project challenges and deliver the desired level of new NPP investment, with some severe limits.

A.   Why stop with RAB?

NECG understands the need for Great Britain to switch the approach to providing incentives for new NPP investment, given the limits of the CfD approach.  In the NECG submission to the BEIS Inquiry on Financing Energy Infrastructure[3], we outlined a range of options including regulated asset approaches.

If Great Britain is willing to seriously consider the RAB model for a few new NPP investment, it is one small step further to consider a more direct Government role in new NPP projects. A simpler, more efficient, faster, more certain, and more flexible approach might involve the creation of a new “National New NPP Development Crown Corporation.”

This new entity would act as an owner or funder of new NPP projects from inception to commercial operation, with NPP project risks and benefits during development and construction remaining with HMG. This new NPP Crown Corporation could allow the Government to optimize the new NPP fleet build programme (i.e., sites, timing, amount of capacity, resources, lessons learned); could reduce capital costs significantly; and would provide the Government with a great deal of leverage.  Once completed, the ready-to-operate NPP projects could be auctioned to market.

This approach could also incorporate several market features, including:

• Competition from programme managers, vendors, technologies, and developers/builders to provide NPP equipment and services to the Crown Corporation;
• Competition for funding, with credit support from the Government; and
• The auction of completed and operational NPP projects to private investors, with suitable revenue support (CfD, RAB, PPAs or Critical Infrastructure Contracts, or other); and
• Revenue support measures developed at market conditions at the time of the auction, rather than 5 to 10 years earlier.

The RAB model should be benchmarked against such a Crown Corporation approach.

B.   What is the objective for British nuclear power industry?

The RAB model should consider the objectives for the nuclear power industry in Great Britain.

• A few new NPPs – If the Government is satisfied with one or two additional new NPP and is not concerned if these new NPPs are developed and owned by SOEs, the current CfD approach and the proposed RAB Model may both be feasible options. In either approach, we expect that a separate agreement for each new NPP project between the Government and foreign government owner would be negotiated. The RAB model might lead to lower electricity rates than the CfD approach, depending on details of the commercial arrangements negotiated.
• A new commercial NPP fleet – If the Government seeks competition, new investors, less political intervention, a new nuclear power industry, and potentially more than one or two new SOE-owned NPPs, then a new approach must provide long-term resolution of key issues.

Any new NPP investor will want assurance about revenue risk.  Both the CfD approach and the RAB model can do this, but the RAB model may do so at lower cost and with greater flexibility than the CfD approach.

New NPP investors will also want help managing completion risk.  The RAB model helps with this, but depends on how risk is assigned.  Key issues include what costs are included in regulatory arrangement (i.e., development costs prior to Financial Investment Decision, project implementation costs prior to start of nuclear construction, construction costs thru commercial operation date, or other) and how risk/liability for poor performance or NPP project non-completion are allocated.

In our opinion, a new RAB model for nuclear power will be too difficult and complex to form the basis for a long-term nuclear industry and will only lead to one or two negotiated RAB model NPP projects.

A Crown Corporation approach would be a more straight-forward approach to delivering new NPP capacity.

C.   Will the RAB model work?

Developing and implementing the RAB model for new NPP investment in Great Britain will require a lot of work, take a long time, will face political and public opposition, and most importantly, it may not deliver the desired level and type of new NPP investment.  The regulated nuclear utility approach in the U.S. also faces challenges, despite decades of successful experience in delivering new NPP investment.

Developing and implementing a RAB model that is balanced and meets the various stakeholders’ objectives (including consumers and NPP investors) will be a substantial task.  This process may be more difficult due to the complexity of the RAB model.

Further, it is unclear who would make new NPP investment in Great Britain under a RAB model. The British RAB approach appears to assume that new entities will come forward to develop new NPP projects.

In concept, the Horizon and NuGeneration projects might have moved forward under a RAB model, but the corporate transformation issues (i.e., nuclear industrial companies striving to become NPP developers, NPP EPC vendors, NPP long-term investors, and NPP Operators) added to the already large challenges faced by any new NPP project.

If the British RAB approach is aimed at U.S. regulated nuclear utilities (e.g., Exelon, Duke, Entergy), a closer focus on how to encourage these companies to invest in new British NPPs should be considered.  Most of the U.S. existing and operational NPPs, and the one NPP now under construction, are regulated utility investments.

An RAB model negotiated with a relatively small number of new NPP investment projects raises issues about whether the time and work to develop and implement the RAB model can be justified.

If the British RAB model only delivers more SOE nuclear project developers, it may be easier to achieve this with other approaches (i.e., the CfD approach).

D.   Long-term stable approach needed

Any approach to delivering new NPP investment in Great Britain, including the RAB model must provide a way for the NPP developer to address completion risk and revenue risk.

Completion risk can be addressed through the RAB model, if properly structured, or by more direct involvement by the Government in the NPP project during development and construction.

Revenue risk can be addressed through a long term, stable revenue stream that is known early in the NPP development process (i.e., before development starts and certainly before the NPP investment decision) even if the revenue will not be received until after the NPP is completed and placed into commercial operation.  The revenue must be assured by a creditworthy counterparty.

In the BEIS Consultation web site, there is a suggestion that the RAB model might be used to help “finance future new nuclear projects, alongside the existing CfD model.”  This suggests that NPP project revenue after commercial operation would be composed of at least two different sources of revenue with different approaches – the RAB return payments based on capital investment and CfD payments linked to electricity market prices and sales.  This will increase the complexity of the arrangements both for the Government and related entities (i.e., regulators) and for the NPP developer, as both streams of revenue must be assessed to support an NPP financial investment decision.

NPP developers and owners will be focused on returns over the initial decades of operation, but also concerned about revenue and returns for the entire NPP operating life, including potential for life extensions.  Electricity markets may allow the NPP to shift to more reliance on market revenue after some initial period (i.e., after debt repayment).  However, as the experience with U.S. merchant nuclear plants has shown, electricity market revenue alone may not cover cash generating costs, especially in a future, more volatile, decentralized market environment.

E.   Sharing Completion Risk

One large issue for any new NPP is completion risk; this is the risk that the NPP will take longer than planned and/or will cost more than planned.  The situation in the nuclear power industry has shown that this risk is real and large.

The RAB model has a process of sharing completion risk.  The approach suggests that an NPP developer may have made a financial investment decision, started construction, and experienced cost overruns and/or schedule delays before having a clear view of how much, if any of the increases in capital cost will be recovered in regulated returns.  Also, this NPP developer may face the situation where regulatory returns are only available if the NPP project is completed, even if completion means a loss for the NPP developer.

The RAB model must include a process to reach an agreement between the NPP developer and the economic regulator in the event of NPP project cost overruns or delays to either:

• Proceed with the NPP project with an agreed increase in regulated asset recovery amounts; or
• Abandon the NPP project with recovery of the amounts spent to date.

F.   Construction Work in Progress

RAB proposed to lower the financial risk to NPP project developers by allowing recovery of returns on amounts invested during the construction process.  There is a track record in Great Britain and in some U.S. states (e.g., Georgia) that this will lower financing costs due to better rates and avoidance of accrued Interest during Construction that would otherwise build up during the construction process.

However, in the context of British electricity market and nuclear new build timelines there may be tax and accounting issues that could offset some of these benefits (e.g., accrued revenues during construction may be treated as corporate liabilities / debt).

G.   NPP project development costs are an important issue

The costs incurred by an NPP developer include development costs (e.g., design, licensing, site preparation, engineering, and other activities leading up to a financial investment decision and the start of NPP construction). The total NPP asset value subject to regulatory treatment should include these costs.

The problem is that some or all these development costs must be incurred to have a clear view of NPP project economics, to enter into an agreement for RAB or other incentives (e.g., CfD approach), and to support a financial investment decision.  In some instances, the NPP developer may decide not to proceed after making a significant investment in these development costs.

If these development costs are only recovered if the NPP is completed and placed into operation, this will make the NPP development process riskier and more uncertain for developers.

Great Britain should consider if and how the RAB model could provide a means for NPP developers might recover these costs if they do not go forward to complete the NPP.  This would increase the potential that real NPP projects will proceed to a successful financial investment decision.  For example, some U.S. States have an approach to allow regulated utilities to incur and recover in rates the cost of developing a nuclear power option, including, in some instances, the cost of obtaining an NRC license.

On the other hand, if this approach is too generous, it could lead to less well-prepared developers moving forward, with resultant difficulties during project implementation.

H.   RAB model should be simple and linked to other programmes

Some have noted that the CfD approach included long, complicated, and difficult to understand documentation and agreements. The RAB model appears even more complex than the CfD approach.

The RAB model and its implementation should not be done in isolation, but should include other financial support and risk reduction measures.  Presumably the discussions concerning the Horizon project about how HMG could aid in the overall financing and the ideas in those discussions (e.g., a Loan Guarantee Programme) may be useful.

I.   U.S. regulated nuclear may provide useful lessons

The British RAB approach has had its main applications in the privatization of Government entities, with an administrative determination of regulated assets based on issues other than actual capital investments in the regulated companies.

There is a long and rich history of U.S. regulated nuclear investment.  The U.S. experience is centred on regulated monopoly utilities that invest in NPPs as a part of the generation portfolio they need to meet customer demand, different from the standalone NPP projects anticipated in Great Britain.

The U.S. experience covers multiple states, each with a different approach and different economic regulator.  The U.S. experience has included NPP projects with cost overruns and schedule delays and economic regulator responses that include prudence reviews and disallowances. In a response to earlier NPP issues, some states implemented processes to limit regulatory uncertainty for both NPP developers and economic regulators (e.g., Integrated Resource Planning processes and nuclear option allowances).

The U.S. regulated utility approach has a century of experience covering investment in many completed NPPs and many more NPP projects that were abandoned prior to completion.  The U.S. utility regulatory approach has a solid legal basis, with decisions in multiple legal cases over many decades providing guidance and limits.  Great Britain has less experience with the RAB model and no experience with new NPPs developed as regulated assets.

IV.   Conclusion

The British RAB model may work to deliver new NPP investment.  However, the RAB model presents significant uncertainty to NPP developers, may not be fully developed and implemented for some time, and may not be attractive to NPP developers, investors, and lenders. Also, the RAB model will need to be combined with other NPP project financial support and risk reduction measures.

Great Britain should also consider other simpler and faster approaches, such as setting up a new Crown Corporation to invest in new NPPs.

This NECG Commentary was written by Edward Kee, Ruediger Koenig, Paul Murphy, and Xavier Rollat.

Notes

[1]              In this scenario, due to lack of competition, it would be difficult to assess what a fair, price and risk would be. Rather, the negotiated result would likely be determined by arbitrage against other non-nuclear capacity and energy generation alternatives (i.e., willingness to pay).

[2]              This would be determined and monitored through ex ante agreements with, and ex post reviews by, the economic regulator that oversees the NPP (e.g., “prudency” reviews by US state-based economic regulators).

[3]              See https://nuclear-economics.com/2019-04-02-necg-submission-to-uk-inquiry-financing-energy-infrastructure/

PDF version

The post #30 – UK RAB Model appeared first on Nuclear Economics Consulting Group.

In May 2019, Exelon decided to retire the Three Mile Island unit 2 early, despite the plant having NRC approval to operate until April 2034.  The Pilgrim nuclear power plant in Massachusetts will close in May 2019, despite the plant having NRC approval to operate until June 2032.

The International Energy Agency (IEA) Nuclear Power in a Clean Energy System report makes the point that nuclear power is needed to transition to a sustainable, low-carbon electricity system and that all existing nuclear power plants should operate for as long as safely possible.

Closing an operating nuclear power plant will result in higher air emissions because the electricity generated by the retired nuclear power plant output will be replaced by dirty combustion-based electricity.

US operating nuclear plants are retired early because the owners of these plants are losing money selling power at wholesale electricity market prices that are lower than cash generating costs.

US electricity markets focus only on low short-term wholesale electricity market prices.  These electricity markets:

• Ignore air emissions and other environmental impacts;
• Ignore long-term electricity system reliability and capacity planning;
• Fail to support clean and reliable nuclear power;
• Allow the replacement of nuclear power by dirty combustion-based power plants; and
• Allow increased, and risky, reliance on a single generation fuel (i.e., natural gas).

Does the US really want electricity markets that are designed to deliver dirty and risky electricity?

PDF version

The post #29 – Another Win for Dirty Electricity appeared first on Nuclear Economics Consulting Group.

The biggest opportunity for the global nuclear power industry today is Saudi Arabia. Originally, Saudi Arabia planned a fleet of sixteen or more reactors to help it meet growing demand for electricity, to help shift to a cleaner post-petroleum electricity system, and to add skilled jobs to the Saudi economy. Now, they have scaled down their nuclear power program to a few plants.  The supplier of the first few Saudi nuclear power plants (NPPs) will be in a strong position to build the larger nuclear fleet that Riyadh is likely to build.

Five nuclear power vendors are competing for the nuclear power sale to Saudi Arabia, with Westinghouse facing off against nuclear state-owned enterprises (SOEs) from Russia, China, France, and South Korea.

A few decades ago, the US was the world leader in nuclear power technology and was able to succeed in the export market on the basis of its large domestic nuclear power fleet and a proven nuclear industrial capability. Today, the US nuclear power industry is trying to sell nuclear power plants (NPPs) in the export market in order to sustain US domestic nuclear industrial capability and to position itself for future nuclear export opportunities.

The US nuclear power industry is a collection of private, shareholder-owned companies that faces two primary roadblocks in the nuclear power export market:

• The US commercial nuclear power industry has difficulty matching the attractive commercial offers from the nuclear SOEs; and
• The restrictive US approach to non-proliferation may limit nuclear power exports, compared to other countries with less stringent requirements.

Commercial Issues

New reactor designs from US companies are excellent, but not inherently best-in-class, compared to reactor designs offered by competing nuclear SOEs.

In contrast to the American commercial market-driven approach to the nuclear power industry and to nuclear power exports, nuclear SOEs in China, Russia, and other countries see nuclear power as a part of larger government-to-government (G2G) relationships. In addition to financing/funding for nuclear power projects through G2G loans, SOE nuclear export offers are thought to include favorable pricing and acceptance of completion risk.

These nuclear SOEs use the nuclear build programs inside their countries to support their nuclear power exports. Using a combination of state-owned nuclear industrial champions and state-owned electric utilities, these nuclear SOEs develop and build new domestic NPPs. The domestic nuclear fleet build enables the nuclear SOEs to gain nuclear industry experience, demonstrate their own reactor designs, and develop a proven nuclear power supply chain – all of which support nuclear power exports. These nuclear SOEs are in the export market to earn hard currency, to import jobs for their domestic nuclear industrial companies, to establish long-term nuclear plant services and fuel customers, and to support broader geopolitical objectives.

China and Russia have recently expanded the powers of their nuclear SOEs, widening the gap between the capabilities and market offerings of these enterprises and the private US nuclear power industry.

In Russia, the vertically-integrated nuclear company, Rosatom, is a key player in domestic and foreign energy policy that aims to preserve and strengthen Russia’s global market share and influence. Russia’s ongoing and planned projects include: Bangladesh, Belarus, China, Egypt, Finland, Hungary, India, Iran, Turkey, and Uzbekistan.

Russian investments are aimed at completing the first floating NPP, expanding its nuclear-powered icebreaker fleet, growing its presence in global nuclear fuel markets, and engaging in several advanced reactor projects.

China is a relative newcomer to the nuclear power industry, but it has consolidated its nuclear enterprise through state financing for energy sector infrastructure and its Belt and Road Initiative (BRI) strategy both at home and abroad. China has grand export plans for nuclear power that are built on exports to Pakistan, a deal with Argentina, multiple initiatives in the United Kingdom, and a place on the Saudi Arabia nuclear vendor short list.

Chinese investments are focused on its rapidly growing domestic nuclear power fleet, several planned advanced reactor projects, developing floating NPPs and nuclear-powered icebreakers, and ambitions for a nuclear-powered aircraft carrier.

Both countries are seeking nuclear power footholds in other countries in Europe, Eurasia, Africa, and South America.

A February 2019 meeting between President Donald Trump and US commercial nuclear industry players highlighted several messages, including arguments that the US domestic nuclear power industry needs support from the federal government, that commercial US nuclear power industry needs government assistance in the export market, and that advanced reactor technology is a way for the US to regain nuclear industrial leadership.

In order to compete in the nuclear power export market against nuclear SOEs, the US must develop and implement
a national nuclear power strategy that supports the domestic nuclear power industry (e.g., existing and new NPP projects),
nuclear technology innovation (e.g., advanced reactors), and nuclear exports.

The US domestic nuclear power fleet, still the largest in the world, may no longer support US nuclear companies in the export market. The credibility of the US nuclear power industry in the export market is diminished by the lack of new domestic NPP projects in the US, in contrast to Russia and China which are continuing to build and demonstrate nuclear capacity at home.  The track record on the few new US nuclear power projects, including Vogtle cost and schedule issues and the abandonment of V.C. Summer, is less than stellar. These issues, combined with the early retirement of existing US NPPs, present reputational risks for the US nuclear power industry.

US nuclear industry companies competing in the nuclear power export market do not have access to the sort of government-sponsored financing used by nuclear SOEs, making it nearly impossible to level the playing field with Russia and China. The level of support that might be offered through OPIC, or the new US Development Finance Corporation (USDFC), falls short of what nuclear SOEs can offer.

While advanced reactor technology research and development is being pursued in the US and in other countries, a new advanced reactor concept will only be a viable commercial power plant option after the concept is used in an actual power plant project. An advanced reactor demonstration project could demonstrate that the advanced reactor concept is valid, that the new advanced reactor design has added value compared to earlier reactor designs (e.g., higher safety, lower cost, flexible operation, and other metrics), and that the new reactor designs can be the basis for a viable commercial power generation investment option.

Unfortunately, prospects are dim for any new nuclear power plant in the US, much less a first-of-a-kind advanced reactor project that layers technology risk on top of nuclear power project risks and costs. Washington could help move these advanced reactor concepts into commercial reality by taking a page from the nuclear SOEs to fund and build one or more advanced reactor power plant projects in the US. Such projects in the US would be a strong advertisement for sales of the new advanced reactor design in the export market.

A comparison to US natural gas exports is apt. While American natural gas exports are not state sponsored and the success in the world natural gas market is largely due to private companies (e.g., by developing disruptive extraction techniques and investing in liquification facilities), the US government’s willingness to actively champion natural gas exports for economic and geopolitical purposes should not be discounted. Nuclear power needs at least the same level of engagement on domestic activity and export promotion as the natural gas industry.

The US government should take actions to support and maintain the US commercial nuclear power industry. This should include resolving issues in the US domestic nuclear power industry to avoid the economic retirement of additional existing NPPs with decades of useful life remaining, supporting new US NPP projects that use existing reactor designs, and supporting US demonstration projects using new advanced reactor designs.

The US government should also take actions to assist US commercial nuclear power companies compete in the nuclear power export market.  US NPP exports, along with goods and services, create a long-term political relationship over an NPP operating life of sixty years or longer.

Proliferation Issues

In addition to resolving the commercial issues, the US needs to rethink its approach to exporting nuclear power technology, fuel, and services, which is linked closely to imposing a US view of nonproliferation.

The US approach to non-proliferation conditions exports with bilaterally-mandated nonproliferation agreements that may restrict uranium enrichment activity and other activity.

A few decades ago, when the US was the world leader in nuclear power technology, it used nuclear technology exports to promulgate its view of non-proliferation by exporting nuclear power technology only to countries that agreed to sign a bilateral treaty (i.e., a 123 agreement). Some countries (e.g., the UAE) were asked to sign a 123 agreement that limited the purchasing country’s activity in uranium enrichment and spent fuel reprocessing, both of which might be used to develop a nuclear weapons program. This was referred to as the Gold Standard for 123 agreements. The US could limit the potential pathway to nuclear weapons for signing countries, and US companies could sell nuclear technology, fuel, and services to the signing countries. However, US nuclear non-proliferation standards may be at odds with increased global competition in the nuclear power industry from countries that may not require these restrictions.

Increased insistence in the US for a Gold Standard Section 123 agreement with Saudi Arabia, that entirely prohibits enrichment and reprocessing of nuclear fuel, as opposed to a standard 123 agreement that only applies to enrichment and reprocessing with US nuclear technology, may limit success in the nuclear power export market. In contrast, Russia and China do not impose the same requirements on existing and planned nuclear power plant sales.

he US view of proliferation implicitly assumes that new nuclear countries should or must rely on global markets and imported nuclear fuel, rather than developing a complete nuclear fuel cycle of their own. In an ideal world, relying on imported nuclear fuel and global markets may be feasible. However, this may add a significant risk to a very large NPP investment (i.e., no nuclear fuel means no power generation, which nullifies the asset value, and may result in electricity grid failures).

However, new nuclear countries are reluctant to give up uranium enrichment because of their need for nuclear fuel security. A country considering a new NPP program will have legitimate concerns about nuclear fuel security and the availability of nuclear fuel over the life of the country’s NPPs.  In addition to commercial concerns, these countries will also have national infrastructure concerns.  A comprehensive nuclear fuel security assessment will consider options to establish a capability to produce nuclear fuel (i.e., including uranium enrichment) inside the county.

US nuclear fuel security has largely been relegated to the utility owners of NPPs, which view this as a commercial issue to be addressed through nuclear fuel procurement strategies. However, even the US has concerns about nuclear fuel security as the nuclear fuel capability has atrophied. Most (i.e., about 95%) of the uranium used in US nuclear fuel is imported and the 2018 Section 232 investigation into uranium imports is focused on US national security issues arising from this reliance on uranium imports. The US no longer has operating uranium conversion capability, after the only remaining conversion facility, the Honeywell Metropolis facility, stopped operation in 2017. The only US uranium enrichment capacity is the foreign-owned Urenco facility in New Mexico that uses non-US enrichment technology. A 2019 US DOE HALEU Demonstration Project will restore some US-origin enrichment capacity.

Reducing or removing nuclear fuel security concerns in countries looking to buy NPPs will help convince these countries to reconsider the need for indigenous uranium enrichment capability. With this in mind, the US should craft a new approach to nuclear fuel security that is linked to NPP exports and Washington’s stringent nonproliferation conditions should evolve to address legitimate nuclear fuel security considerations.

Conclusions

Having nuclear power brings countries into a special club, with benefits of nuclear power including energy diversification, energy independence, and clean and reliable baseload electricity generation. Foreign nuclear plant buyers may want American nuclear power technology and a deeper relationship with the US, but they are hard-pressed to reject more attractive commercial deals from SOE nuclear vendors that do not require purchasing countries to restrict activity in uranium enrichment.

Without US government action to resolve both commercial and nonproliferation issues, the long-term foreign and security policy dividends that accompany nuclear power exports will be ceded to American competitors. In the meantime, China and Russia’s nuclear SOEs provide them a key advantage in an age of increased great power competition.

This Commentary was written by Melissa S Hersh and Edward Kee.

A shorter version of this Commentary was published in the Atlantic Council EnergySource.

PDF

The post #28 – Roadblocks for US Nuclear Exports appeared first on Nuclear Economics Consulting Group.

Recent History

Three existing nuclear power plants have retired early since 2013 for purely economic reasons.  Kewaunee closed in May 2013, Vermont Yankee closed in December 2014, and Fort Calhoun closed in October 2016.  Revenues in the electricity markets were not sufficient to cover the costs to operate these nuclear power plants.

Two more existing nuclear power plants retired early because of the high cost of major maintenance. Crystal River closed in February 2013 and San Onofre closed in June 2013.  If the value of nuclear-generated electricity had been higher, the owners of these plants might have justified the cost of the major maintenance needed to return the plants to full operation.

Oyster Creek in New Jersey was retired early in 2018. The plant’s operating license would have allowed operation until 2029, but Exelon and the state of New Jersey agreed that the plant could operate until 2019 without a requirement to retrofit expensive cooling towers. Exelon then decided to close the plant a year earlier than required.

Some other existing nuclear power plants were scheduled for early retirement for economic reasons, including Nine Mile Point, FitzPatrick, and Ginna in New York and Clinton and Quad Cities in Illinois.  In response to the scheduled early retirements, New York and Illinois developed and implemented Zero-Emissions Credit (ZEC) programs.  The additional revenue from the New York and Illinois ZEC programs kept these threatened nuclear power plants in operation. These ZEC programs are appropriate actions by government to stop market failure.

This Commentary is an update on what has (and has not) happened over the past year or so to prevent more early retirements.

Federal Actions

Little has happened at the federal level to stop nuclear power plant early retirements.  The Supreme Court has been asked to review appeals court decisions upholding the Illinois and New York ZEC programs, DOE’s resilience initiative was stopped and additional action is on hold, and the NRC’s review of license renewal applications (both initial and subsequent) is going well.

Supreme Court

The New York and Illinois ZEC programs were challenged in court.  So far, the courts have rejected filings intended to stop ZEC programs.  In January 2019, a coalition of power generation companies asked the U.S. Supreme Court to review the Seventh Circuit Court of Appeals decision affirming lower court decisions upholding the Illinois ZEC programs.  The industry seems to believe that the Supreme Court is unlikely to overturn the Appeals Court decisions related to the Illinois ZEC program, or the related Second Circuit Court of Appeals decision on the New York ZEC program.  Overturning these Appeals Court decisions would overturn the earlier Hughes v. Talen Supreme Court decision and would likely cause problems with existing renewable energy programs in many U.S. states.

DOE Initiatives

In September 2017, the U.S. Department of Energy (DOE) sent a Notice of Proposed Rulemaking (NOPR) to the Federal Energy Regulatory Commission (FERC) that was aimed at maintaining the resilience of the U.S. power generation system.  This NOPR would have provided cost recovery for power plants that have 90 days of fuel at the plant site (i.e., nuclear power plants and most coal-fired power plants).  FERC rejected the DOE NOPR and asked regional market/system operators to assess system resilience issues.

In 2018, FirstEnergy asked DOE to issue an emergency order that would provide cost recovery to coal and nuclear power plants in PJM.  This request, and a revisit of the DOE NOPR, are on hold and may not be pursued.

NRC

There is some good news for existing nuclear power plants at the Nuclear Regulatory Commission (NRC). Some existing nuclear power plants see an opportunity to operate for much longer.  Most U.S. existing nuclear power plants have applied for and received approval for an initial 20-year license renewal, allowing the nuclear power plant to operate for a total of 60 years.

The initial license renewal application under review for Seabrook was approved by the NRC on 12 Mar 2019 [updated on 18 Mar 2019].

Also, the NRC has started a process to review applications for subsequent license renewal (SLR) that would, if approved, allow a nuclear power plant to operate for a total of 80 years. Turkey Point in Florida, Peach Bottom in Pennsylvania, and Surry in Virginia have filed an SLR application and North Anna in Virginia has indicated that it will file an SLR application in 2020.

State Activity

Arizona

In 2018, an Arizona ballot initiative on renewable energy, Proposition 127, was rejected.  Proposition 127 would have required Arizona electric utilities to obtain at least 50% of electricity from renewable energy by 2030, with nuclear power not included in the definition of renewable energy.  The defeat of Proposition 127 is seen as success for the Palo Verde nuclear power plant, which was projected to retire early if Proposition 127 was approved and implemented.

California

In early 2018, the California Public Utilities Commission (CPUC) approved a plan to allow the Diablo Canyon nuclear power plants units to retire at the end of their original 40-year NRC operating license in 2024 and 2025 with Pacific Gas & Electric (PG&E), the owner of Diablo Canyon, not applying for a 20-year initial license renewal from the NRC for the units.

The PG&E deal anticipates that the clean electricity from Diablo Canyon will be replaced by other carbon-free resources, but the details and cost of the power to replace Diablo Canyon will not be known until a later Integrated Resource Plan proceeding.

California has aggressive targets for reducing carbon emissions (i.e., 100% zero-carbon electricity by 2045) that will be harder to achieve when the Diablo Canyon nuclear power plant closes early.

Connecticut

Dominion Energy, the owner of Millstone, announced that an agreement was reached under a 2018 Connecticut program to solicit carbon-free generating capacity [updated on 18 Mar 2019].  Connecticut selected a 10-year bid from Millstone, after which state regulators concluded that Millstone was at risk of retiring early.

Illinois

The Illinois ZEC program has been successful in preventing the early retirement of the Quad Cities and Clinton nuclear power plants.

In early 2019, there are reports that three other Exelon nuclear power plants in Illinois (i.e., Dresden, Braidwood, and Byron) face potential early retirement.  All three of these nuclear power plants have capacity contracts that will prevent closure until 2021 for Dresden and until 2022 for Byron and Braidwood.

Negotiations between Exelon and state lawmakers are in progress.

In the meantime, new Illinois legislation has been proposed that would put aggressive renewable energy targets in place (i.e., 45% by 2030 and 100% by 2050), with nuclear power excluded.

Iowa

Duane Arnold received approval of an initial license renewal that expires in 2034.

A power contract extension to 2025 was approved by the Iowa Utilities Board in 2013.  In 2018, a settlement agreement that would end the power contract in 2020 was approved by the Iowa Utilities Board.  The Duane Arnold nuclear power plant will close in 2020.

Massachusetts

Pilgrim received approval of an initial license renewal that expires in 2032.

Pilgrim will close in June 2019 and Entergy has agreed to sell Pilgrim to Holtec International, who will carry out the decommissioning.

Michigan

Palisades received approval for an initial license renewal that expires in 2031.

The Palisades nuclear power plant in Michigan will retire early when the power contract with Consumers Energy ends in 2022. Entergy announced that it has agreed to sell the Palisades nuclear power plant to Holtec International after shutdown, with Holtec taking over decommissioning of the plant.

Minnesota

Prairie Island nuclear power plant in Minnesota is considered as one of the existing nuclear power plants potentially threatened by economic early retirement as a result of relatively high costs (i.e., small, single unit plant) and low power market prices.

In early 2019, Minnesota proposed a plan for the state’s electricity to be carbon free by 2050.  Xcel Energy, which owns the Prairie Island and Monticello nuclear power plants in Minnesota, has its own plan to be carbon free by 2050 and to reduce carbon emissions by 80% by 2030.  Nuclear power appears to be a part of both plans.  However, there are several issues:

• Nuclear power plants in Minnesota may not operate much beyond 2050. Prairie Island unit 1 and 2 started operation in 1974 and both have approved initial license renewal applications that extend the operating licenses to 2033/2034.  If these units received an SLR (there is no application filed for this), operation might continue to 2053/2054.
• The actual legislation introduced in the Minnesota house to implement the carbon-free goal, HF1956, excludes existing nuclear power plants in Minnesota from the definition of a “carbon-free resource.”
• The proposed legislation appears to allow new nuclear power plants in Minnesota as a carbon-free resource. However, new nuclear power is banned in Minnesota and legislation to end this ban is being discussed.

The carbon-free electricity plans of Minnesota and Xcel Energy offer some hope that existing Minnesota nuclear plants will not retire early, but these plans are not certain.

New Jersey

In 2018, New Jersey passed legislation that required the Board of Public Utilities (NJBPU) to develop and implement a ZEC program.  The NJBPU approved a ZEC program in November 2018 and initiated the ZEC process.  Public Service Enterprise Group (PSEG) submitted ZEC applications for three nuclear power plants (i.e., Hope Creek, Salem unit1, and Salem unit 2).

The NJBPU is scheduled to consider the applications and the analysis conducted by BPU staff and consultants in an April 2019 meeting.

The New Jersey ZEC process has generated some public controversy before any outcomes have been made public.  State Rate Counsel testimony stated that the PSEG nuclear plants should not qualify for ZEC payments and PSEG asserted that the nuclear plants will close early if there are no ZEC payments.

The New Jersey ZEC legislation, and the NJBPU process to implement that legislation, provides a path to preventing the early retirement of the PSEG nuclear power plants, but this process is not completed yet.

New York

Entergy has announced that the Indian Point units will retire early in 2020 and 2021.

Entergy, filed an application for license renewal in 2007 for the Indian Point units, more than 5 years before the original licenses were due to expire in 2013 and 2015.  The units continued to operate after the original license expired because the license renewal applications were under review by the NRC.

In 2018, Entergy reached an agreement with the state of New York and environmental groups that had opposed the license renewal that involved Entergy amending the license renewal applications to cover a shorter period.  The NRC approved a truncated license renewal that allowed the units to operate until 2024 and 2025.

Entergy is expected to sell the Indian Point Energy Center, after units 2 and 3 are closed, to a firm that would carry out decommissioning.

Ohio

FirstEnergy has announced plans to close two Ohio nuclear power plants early.  Unless the plants receive more revenue from state or federal sources, Davis Besse will close in 2020 and Perry will close in 2021.

These nuclear power plants have been under threat for some time.  A 2016 state plan to re-regulate the units was not successful.  FirstEnergy asked DOE to issue an emergency order that would provide additional revenue to its nuclear power (and coal) power plants in early 2018.  Not long after the DOE emergency order request, the FirstEnergy competitive generation subsidiary (FirstEnergy Solutions) that owns the company’s nuclear power plants filed for Chapter 11 bankruptcy protection.

In 2018, legislation is expected to be considered that would provide additional revenue to the Ohio nuclear power plants. Past state efforts to stop the early retirement of the Ohio nuclear power plants have been defeated and this new plan is expected to face strong opposition.  The potential to include renewable energy in the bill may help gain support.

Pennsylvania

FirstEnergy has also announced plans to close its Beaver Valley nuclear power plant in Pennsylvania in 2021 unless it receives additional revenue.

Exelon has announced plans to close Three Mile Island unit 1 (TMI-1) in 2019 unless it receives additional revenue, with a closure decision coming as soon as June 2019 (i.e., when Exelon needs to order nuclear fuel) for a September 2019 closure.

In March 2019, Pennsylvania PUC Commissioner Andrew Place sent a report on policy options for nuclear power to legislators.  On 10 March 2019, legislation was introduced that could save the threatened Pennsylvania nuclear plants by requiring that nuclear power plants receive the same preferential treatment and subsidies that renewables get under a 2004 law.

Earlier efforts to pass legislation to help avoid early retirement of Pennsylvania nuclear power plants have failed and this new legislation faces strong opposition.

Wisconsin

Wisconsin has proposed a plan to require electric utilities to be carbon-free by 2050.  The plan would include nuclear power as a source of carbon-free electricity.  This may help the Point Beach nuclear power plant remain viable, depending on the details of the state plan.  However, Point Beach may not operate past 2030, as the plant received NRC approval of an initial license renewal and has a current license expiring in May 2030.  Even if Point Beach applied for and received an approval for Subsequent License Renewal, that would only last until 2050.

Summary

There are some positive trends for U.S. existing nuclear power, but some near-term decisions may mean that multiple units are likely to retire early. Federal initiatives to limit the early retirement of existing nuclear power plants have not moved forward.  This means that states must take action.

The following table provides a summary of the existing nuclear power plants that are scheduled to retire early and some key units that are threatened by early retirement.

PDF

The post #27 – US Nuclear Still Threatened appeared first on Nuclear Economics Consulting Group.

Reforming the electricity industry while maintaining a viable nuclear power industry during and after the nuclear power restart process is an important challenge for Japan.

Japan is restarting its nuclear power industry and has set a target for 2030 electricity production from nuclear power of 20-22%.

Japan began the process of restructuring and reforming the electricity industry in 1995, with reforms accelerated after the Great East Japan Earthquake and the Fukushima Daiichi accident in March 2011. Most Japanese electricity industry reforms were completed in 2016, when the retail market was liberalized. Wholesale electricity competition is increasing and final electricity industry reforms are to be completed in 2020.

Meeting nuclear electricity production targets in 2030 will require a nuclear power industry that can meet the challenges of the restart process while remaining financially viable.  Doing this within the context of the electricity industry and market reforms will be an important challenge for Japan.

This Commentary looks at the situation with respect to nuclear power, the strategy for nuclear power in the future, and how the next phase of electricity industry reforms is likely to influence the Japanese nuclear power industry.

Nuclear power situation

[Updated 26 Feb 2019[1] At the beginning of 2011, Japan had 55 operating nuclear power units (including Monju FBR) with a capacity of 49,392 MWe, two nuclear power units under construction with a capacity of 2,756 MWe, one nuclear power unit with approval to start construction with a capacity of 1,385 MWe, and plans for another 12 nuclear power units with a total capacity of 15,375 MWe.

On 26 February 2019, Japan has 37 “operational” nuclear power units[2] with a total capacity of 37,635 MWe, comprised of:

• Nine nuclear power units actually in operation with a total capacity of 9,130 MWe;
• 16 “operational” but idle nuclear power units that have submitted restart applications with the Nuclear Regulatory Authority (NRA), of which six have received NRA approval for restart, but have not yet completed all other requirements for restart; and
• 12 “operational” but idle nuclear power units that have not yet filed restart applications with the NRA.

18 nuclear power units with total capacity of 11,757 MWe were permanently shut down after March 2011.  More nuclear units may be vulnerable to permanent shutdown.

Japanese nuclear power units under construction and planned prior to March 2011 may no longer be viable; all have been deferred and some have been formally cancelled (e.g., Fukushima Daiichi units 7 and 8).

5^th Strategic Energy Plan

The 5^th Strategic Energy Plan, approved in July 2018, established a target for nuclear generation to provide 20-22% of the total electricity generation in Japan by 2030.

Assuming a typical capacity factor, this suggests that about 25,000 MWe of nuclear power capacity will be in operation by 2030.  The 2030 nuclear generation share target:

• is a significant increase in nuclear electricity generation from today;
• will require about 16,000 MWe of operating nuclear generating capacity to be added to the nuclear units now generating electricity;
• will involve a combination of the restart of existing “operational” but idle units, life/license extensions, and the completion of new nuclear power units; and
• implies some “operational” but idle nuclear power units will be permanently shut down.

Meeting the 2030 nuclear generation share target will only be possible if the utility owners of nuclear power plants in Japan consider these nuclear power plants to be financially viable.

The challenge of obtaining permission to restart “operational” but idle units and of completing new nuclear units is significant.  An additional challenge is to ensure that the Japanese nuclear power industry is financially viable as the electricity industry reforms are completed.

Electricity Industry Reform

The Japanese electricity reform process has multiple steps, with most of these steps already completed.

The Japanese retail electricity sector is mostly competitive, with only some small residential retail electricity customers remaining on regulated tariffs until 2020. Electricity retail providers are made up of new entrants and the retail segments of pre-reform electric utilities, some of which operate outside their historical rate areas.

Japanese electricity retailers buy most of their power from legacy electric utilities through bilateral power contracts that are monitored by the Electricity and Gas Market Surveillance Commission to ensure that there is fair competition.  About 10% of power is obtained through trading in the Japan Electric Power Exchange (JPEX) spot market.

Before the electricity market reform, nuclear power plant costs were recovered in tariffs.  Now, there is no guarantee that any electricity generator can recover costs in the bilateral or JPEX power markets.

My review of the most recent annual reports of Japanese electricity companies indicates that these companies are profitable on a company-wide basis.  I was unable to find data on the profitability of nuclear power plants.  Some Japanese electricity utilities have seen a decline in company-wide operating profits over the past few years.

Japanese electricity industry reforms are proceeding in a careful manner.  This is different from some other electricity reform processes that involved large changes and sudden disruptions in the electricity industry.

Final electricity reforms in Japan are to be implemented by 2020 and will include a baseload market, legal unbundling, the end of all regulated retail tariffs, changes to the FIT approach for renewables, capacity markets, zero-carbon electricity markets, and, CfD contracts for nuclear power plants, and other items.

Baseload Market

In 2019, a Baseload Market is to be implemented. In this new market, utilities must bid power from baseload generators at the average cost of those generators less revenue from the capacity market.  Japanese utilities have invested in nuclear power plants based on the expectation that they can improve their market competitiveness as a result of the low (i.e., zero) marginal cost of nuclear electricity. The new Baseload Market may negatively impact the overall profitability of nuclear power plants.

Legal unbundling

Legal unbundling appears to be focused on separating generation businesses from transmission and distribution utilities.  This unbundling does not seem to require that generation companies are separate from electricity retailers or that generators cannot act as retailers.  Generators will continue to be bundled with retailers, to act as retailers, and to provide power contracts to other retailers.  This is far different from the strict legal unbundling in the US, where generation companies were separated from legacy electricity retailer affiliates.  This legal unbundling may have little direct impact on nuclear power plants.

End of regulated retail tariffs

Most electricity customers are already in the competitive market. Regulated tariffs now remaining for some small residential retail customers are to stop in 2020. If the impact of ending regulated tariffs for these small residential customers is negative for customers, there is likely to be some sort of regulated last-resort tariff for small customers.

After the full liberalization of retail electricity market, new retail market suppliers entered the market by adopting a cream-skimming strategy. The profit margins of legacy electric utilities were reduced as their most profitable customers moved to new retail supply companies and the legacy utilities were required to provide continued universal service (i.e., the remaining regulated tariffs for small residential customers) at low or negative margins.  It is likely to be a positive step for nuclear utilities when the last remaining regulated residential tariffs are removed in 2020 and replaced with sales at competitive market prices.

After full liberalization of the retail electricity market, Japanese electric utilities are starting to consider how continued operation of nuclear power plants will impact their financial situation.

Changes to the FIT contracts

In Japan, Feed-In Tariff (FIT) contracts have resulted in a large increase in renewable generation.  Lessons from the U.S., Germany, and other countries are reflected in the Japanese move to end FIT programs and to modify existing FIT contract prices.  This will result in some dislocation in the renewable power project market, but should be effective in preventing a flood of renewable capacity additions in response to high FIT prices (i.e., out-of-market subsidies) as has been seen in other countries.  The changes to the FIT regime are likely to be positive for nuclear power.

Capacity markets

The details of the planned capacity markets are not clear.  The approach appears to involve a separate capacity market in each of the regions (i.e., regions are based on the rate areas of the nine legacy vertically-integrated General Electric Utilities plus Okinawa) that will ensure sufficient capacity is in place in each region to meet reliability targets and reserve margins.

If the capacity market has long-term commitments (i.e., contracts) and payments, this should help nuclear power plants earn additional long-term revenue that will ensure their financial viability.

Zero-carbon electricity markets

The details of the zero-carbon electricity market are also unclear.  This might take the form of zero carbon electricity mandates for electricity retailers, who would then procure zero carbon electricity certificates or credits from generators, including renewables and nuclear power.

Depending on the approach to the zero-carbon electricity market, it could be an additional source of revenue for nuclear power plants.

CfD contracts for nuclear power plants

There have been general discussions of the potential for CfD contracts for nuclear power plants.

Strictly speaking, a contract for differences (CfD) is a financial hedge contract that is tightly linked to a wholesale market spot price.  As the Japanese electricity reforms seem to be moving toward a bilateral contract / balancing market rather than a mandatory gross pool market, these power contracts may resemble conventional bilateral power contracts rather than financial hedge contracts.

These nuclear power contracts would need to have a counterparty (e.g., retail electricity providers and/or the grid company) and a means to recover the costs of the contracts.  It will also be important that these nuclear power contracts do not interfere with the ability of the nuclear power plants to enter into other arrangements (e.g., other power contracts, zero-carbon credits, capacity markets, etc.).

Putting such nuclear power contracts in place to bolster nuclear power plant financial viability will help the nuclear power industry.

Other

JPEX implemented a voluntary bid-based wholesale electricity market in 2017.  About 10% of all electricity is traded on the JPEX spot market.  Changes to the Japanese electricity balancing market and other factors may lead to an increase in JPEX trading activity.  However, the Japanese electricity reforms do not appear to include a transition to a mandatory pool market (e.g., like PJM and other U.S. electricity markets).  Accordingly, Japan may not face the same issues seen in U.S. markets (i.e., spot prices that are sometimes negative, that are not sufficient to meet generator costs, and that not sufficient to provide incentives to build new generation) as a result of subsidized renewable generation.

Overall Assessment

Electricity reform in Japan has both favorable and unfavorable impacts on nuclear power.

METI is monitoring the overall impact on nuclear power profitability as electricity industry reforms move into the final stage.  The Japanese electricity industry generally expects that METI will take action to help nuclear power remain financially viable (e.g., through nuclear CfD contracts) if electricity reforms present problems.

My assessment is that electricity reform in Japan should not prevent it from meeting its 2030 nuclear generation targets..

PDF version

Notes

[1]              JAIF capacity amounts used instead of IAEA PRIS RUP capacity; Genkai unit 2 status changed to permanent shut down; and errors corrected.

[2]              Fukushima Daini units 1-4 are included, but it is likely that these units will be permanently shut down.

The post #26 – Japan – Nuclear Power and Electricity Reform appeared first on Nuclear Economics Consulting Group.

Last weekend I led of team of 20 individuals, including academics, students and army & navy personnel, into the nuclear plant in Northern Japan that was destroyed in March 2011. The plant is based in Japan’s third largest prefecture, Fukushima, which is about the same size as the small Balkan country, Montenegro. The prefecture stretches almost from the Sea of Japan to the Pacific Ocean, and has over 100 km of coastline.

I found that the name of one of Japan’s most important industrial companies, Hitachi, was very visible inside the destroyed nuclear site. The day prior to our visit Hitachi’s stock price on the Tokyo Stock Exchange had risen by 8% on speculation that the company would terminate its investment in a nuclear project at Wylfa in Northern Wales, on the Irish Sea.

Toshiaki Higashihara, the CEO and President of Hitachi, confirmed last week that Hitachi’s investment at Wylfa would indeed be “suspended” and that the company would take a $3 billion write-down on its Welsh nuclear investment.  The reasons for the suspension would appear to be lack of funding and concerns over the profitability of the project.  The write-down will cut Hitachi’s net profit for fiscal 2018/19 by almost 60% compared with previous forecasts. Hitachi has a market capitalisation of $30 billion, and employs over 300,000 staff, or about 0.5% of Japan’s total workforce.  Last year Hitachi announced its biggest ever overseas acquisition when it acquired one of ABB’s power infrastructure businesses for $6.4 billion.

Hitachi’s decision to exit this overseas nuclear project effectively ends Japanese involvement in international nuclear projects, given Toshiba’s decision to exit another UK nuclear project in Moorside, Cumbria and the decision by Japan’s Mitsubishi Corporation to cancel a nuclear project in Turkey in December last year.  Russia and China would now appear to be dominating global new nuclear build and KEPCO, the South Korea electricity monopoly, has recently completed a 5.3 GW nuclear project in Abu Dhabi, reportedly delivered on time and on budget.

The 8th anniversary of the nuclear accident in Fukushima will be in March this year as the prefecture continues to struggle with the damage, both reputational and real. The global nuclear industry in the developed world is still also reeling from the impact of the accident with bankruptcy of Westinghouse in the US, the forced takeover of South Carolina’s electric power utility, SCANA, by Dominion last year, and these latest project cancellations in the UK that may undermine the UK’s commitment to nuclear power.

Japan’s is slowly restarting its nuclear fleet, and Hitachi’s Higashihara said that Hitachi remains committed to commercial engagement in these domestic restarts, and the decommissioning work that flows from dismantling Japan’s older reactors.  The current chairman of Hitachi’s Board of Directors, Hiroaki Nakanishi, who is also chairman of Japan’s power industrial body, Keidanren, is also calling for a more open discussion on Japan’s nuclear strategy. The reactors at the destroyed plant in Fukushima were originally built by General Electric and Hitachi, and Hitachi and Toshiba are playing important roles in decommissioning the plant which may cost more than $200 billion and take four to five decades.

We look forward to monitoring these nuclear developments with you, and discussing them with you in due course.

Kindest regards, Tom.

Tom O’Sullivan
Mathyos Global Advisory
Energy-Security-Infrastructure
Tokyo, Japan
+81-80-1213-5802
http://www.mathyos.com
twitter: @mathyosadvisory

PDF

The post #25 – Hitachi suspends UK nuclear appeared first on Nuclear Economics Consulting Group.

I was honored to participate in this event on the role of government in nuclear power. Governments have been and will continue to be a critical factor for nuclear power.

Assuming that the market will deliver new nuclear power plants is wishful thinking – nuclear power will only be delivered by private investors with a significant role of government. And nuclear power plant development at the scale needed to help with climate change may only be possible as part of a national program.

What works for nuclear power?

Figure 1 in my slides showed existing and operational nuclear power plants and new nuclear power plants (i.e., those which have started nuclear construction).  The large number of nuclear power plants and the range of countries with nuclear power demonstrates that we know how to do nuclear power.

Figure 1 – Existing and new nuclear plants

Figure 2 in my slides added merchant nuclear generation (i.e., red stripes). Few existing and new nuclear power plants are merchant generators and (as discussed in more detail below, some of these face financial stress). The merchant nuclear approach may not be working well, even where significant incentives have been provided to merchant nuclear projects.

Figure 2 – Existing and new nuclear plants – merchant

The conclusion from these charts are:

• The world knows how to develop and build nuclear power plants;
• Most existing nuclear power plants were built by and are operated by regulated or government utilities; and
• Only a few merchant nuclear generators.

Regulated and government nuclear is proven

All operating nuclear power plants were developed and built by government or regulated utilities.

For regulated or government utilities, long-term revenue or cost recovery is virtually certain.

In this approach, nuclear power is part of a vertically integrated electric utility generating asset portfolio.

These regulated and government utilities make investments in generation assets, spend money on power plant fuel and operation, and make decisions about retiring existing assets. These decisions are based on long-term planning processes focused on ensuring reliable operation while minimizing total costs over the long term.

Merchant nuclear plants unproven

A merchant generator is one that depends upon the market for its revenue (i.e., rather than regulated asset with recovery of costs and a return on investment or a government asset with costs covered by the government). The owner of a merchant generator takes significant risk.  A new merchant nuclear project faces significant financial uncertainty due to completion risk.  Financial and market risk after commercial operation may also be significant.

A few existing nuclear power plants operate as merchant generators in the in UK and USA.  All of these existing merchant nuclear plants were originally developed and built by regulated or government utilities, with the transformation into merchant generators coming as a part of electricity industry reform.

Only a few new nuclear power plants are being developed as merchant generators.

Even merchant nuclear projects have government support

While there are several new nuclear projects that are described as merchant generators, none of these projects has total reliance on the market for revenue.  Instead, there are varying degrees of and approaches of government support.

In Turkey, the build-own-operate (BOO) projects are developed around power purchase agreements with Turkish government utilities.  These power agreements provide revenue certainty during early periods, with the owner expecting additional revenue from power sales into the Turkish bilateral power market for some portion of the plant for some of its life.  The Russian merchant nuclear project at Akkuyu is proceeding, while searching for investors.

In Finland, the Mankala model used by TVO and Fennovoima is similar to the generation and transmission cooperative model in the US. In this model the power plant company is a cooperative with membership by energy users. The energy user members invest in a share of the nuclear power plant, pay a share of the investments and operating costs, and get a share of the power generated. TVO itself has relatively low risk, but each TVO member who participates in the OL3 project are taking a share of the total risk of the nuclear project.

In the UK, the Hinkley Point C project has just started nuclear construction.  This project will operate in the UK electricity market, but was provided with a bundle of financial incentives to supported the financial investment.  These incentives include a long-term power contract that removes the risk to project revenue from electricity market price fluctuations. While the owner of this project will face some risks (e.g., cost overruns and delays), it is unclear whether this should be considered as a merchant project.

In my view, the Hinkley Point C (and the linked Sizewell C) project are proceeding only due to the extraordinarily lucrative power contract and other incentives.  Also, these projects are owned by state-owned utilities (i.e., EDF, the French national utility that also owns all operating nuclear power plants in the UK, with CGN, a Chinese national utility as a partner).

The Bradwell project, using the new Chinese Hualong One reactor design, is moving forward but may be driven primarily by China’s nuclear power industry export business strategy.

Merchant nuclear generation faces issues

A standalone privately-owned merchant nuclear company has a large amount of financial risk during construction due to the potential for cost overruns and construction delays.  After commercial operation, a merchant nuclear plant faces market risk.  A key market risk is that the revenue from sales of electricity or other products into the market will be lower than an amount needed to provide returns on and of investments, and may even be lower than cash generating cost. A more recent market risk is that market operations may curtail a nuclear power plant output (or subject the plant to negative spot prices) due to a flood of renewable generation with preferential dispatch.

Merchant nuclear power plant investments are risky and any private financial assessment using typical discounted cash flow techniques will place little value on much of the 80+ year operating life of a new nuclear power plant.  This is because a discounted cash flow analysis using a typical commercial discount rate will show little present value for cash flows that are more than about 30 years in the future.  If this cash flow analysis is done prior to investment, the negative cash flows during the 10-year development and construction period will dominate.

In the US, several existing merchant nuclear plants have retired early due to financial losses due to low electricity market prices and several more merchant nuclear plants are scheduled to retire early in the next few years.  Several new merchant nuclear power plants in the US have received NRC approvals to start construction, but none of these have moved forward.  Several other merchant nuclear projects in the US pulled out of the NRC process before approval was granted.

A recent announcement indicated that the Japanese-led merchant nuclear project in Turkey at SINOP had been cancelled.

Merchant nuclear projects in the UK also face issues.  The NuGen project is now closed because no buyer could be found for the project. The Horizon project, using a proven ABWR reactor design, is moving forward, although there have been recent news stories about financial issues.

What can be done?

It is too much to think that some market economies can shift to centrally planned economies in order to support the nuclear power industry.  It is even difficult to see the electricity industry being nationalized or re-regulated in market economies to support the nuclear power industry.

But there are approaches that can be taken to improve the financial prospects of nuclear power in market economies. [1]

1.            Shift to regulated and government nuclear

Nuclear power plants are large multi-generational assets that provide significant public good.  Like high-voltage transmission lines and interstate highways, this type of asset is typically owned by or regulated by the government.

Some countries have a government utility approach or a regulated utility approach that is embedded in what is otherwise a market economy. This includes parts of the US, France South Korea, and other countries. It may be difficult to make a shift to a centrally planned electricity and nuclear power industry – even if this would make nuclear power more feasible – but such a privatization or re-regulation approach has been considered.

There is precedent for regulated and government nuclear plants to participate in electricity markets.  In the US, California, Virginia, and other states retain regulated asset status for nuclear power plants even though these states (and the regulated nuclear power plants) are participating in wholesale electricity markets.

The only new nuclear project under construction in the US is in the regulated region of the Southeast.  Vogtle, in Georgia, is moving toward completion.  V.C. Summer, in South Carolina, was abandoned after starting construction.  The regulatory framework for new nuclear in Georgia and South Carolina enabled these nuclear projects to proceed.

A new SMR project is being developed in Idaho by NuScale power with a large role of government utilities.  A public power cooperative, Utah Associated Municipal Power Systems or UAMPS (a political subdivision of the State of Utah), will be the investor/owner/power offtaker; another public power utility, Energy Northwest, is preparing to act as operator; the US government is providing a site at the Idaho National Laboratory; and the US government is planning to take some of the plant’s output.

When the UK privatized British Energy for the first time, British Energy faced financial distress in the electricity market and was re-nationalized a few years later.  This is an example for other countries about how to avoid losing the nuclear power industry due to short-run electricity market outcomes.

2.            Avoiding or re-thinking electricity markets

We need to be very careful in how we think about electricity industry reform and electricity markets if we want to keep nuclear as a viable option.

A country that has already reformed its electricity industry reform and implemented electricity markets might consider re-regulating or nationalizing merchant nuclear projects, both existing and new, in order to make that merchant nuclear viable. This should be possible without undoing the entire electricity industry approach and without dismantling the electricity markets.

Electricity markets are inherently short-term and while these markets do a good job at real-time system and power plant dispatch, the resulting spot prices do not and cannot provide incentives for long-term power plant development and construction.  These spot prices may even be too low to allow profitable operation for existing nuclear power plants (e.g., spot prices are below cash generation costs).

The basic premise of these electricity markets is to separate generation from the rest of the vertically integrated electricity industry, and then have those generating assets participate as merchant generators in the market. Markets function around short run marginal costs, and generally ignore fixed generating costs returns on investment and other things that are very important to nuclear generating plant owners.

Avoiding electricity markets and electricity industry reform may be one way to help nuclear. If a country must reform the electricity sector and must put electricity markets in place, the restructuring approach and the market design can be tailored to avoid adverse financial outcomes for existing nuclear power plants and to ensure that the option of new nuclear power plants is not foreclosed.

Japan is restarting its nuclear power industry and projects that a significant portion of national electricity production will come from clean nuclear power.  At the same time, Japan is restructuring and reforming the wholesale electricity industry. Japan’s approach to reform the wholesale electricity industry while maintaining a viable nuclear power industry will be closely examined by all countries considering how to reconcile electricity industry reform and nuclear power.

3.            Financial support for merchant nuclear in electricity markets

If electricity markets are here to stay, there are ways to provide revenue adequacy and certainty to nuclear power. Some argue that electricity market prices can be reformed in a way that will benefit nuclear power, but this is not proven. What is proven is that out-of-market payments can be used to provide additional adequate and certain revenue that can allow nuclear power plants to be financially viable in electricity markets.

In response to potential early retirement of existing merchant nuclear plants, some US states implemented programs to pay nuclear power plants more money for the clean air benefits these nuclear power plants provide.  These so-called Zero Emissions Credits (ZECs) in New York and Illinois have stopped the early retirement of several nuclear power plants in those states.  The ZEC program in New Jersey has been approved and will be implemented in 2019. Connecticut has a clean energy purchase program that may provide similar benefits to nuclear power plants in that state. Absent the ZEC payments, these financially threatened nuclear plants with likely retire early.

Similarly, offering power purchase contracts or contracts-for-difference arrangements to a merchant nuclear plant to increase revenue and to make that revenue more certain is another approach.

4.            Clean energy mandates

Another approach is to establish clean energy mandates. This would replace the pervasive renewable energy mandates with mandates that include (or even focus on) nuclear power. The same approach used to incentivize renewable energy would be applied to nuclear power. After all, the goal of these programs is to reduce the levels of carbon and other air omissions, and nuclear power is a large source of clean energy.

These clean energy mandates would be especially important for nuclear power if the mandates were applied to US government power users and these government power users could enter into long-term contracts with nuclear power plants.

A new report by the US DOE[2] provides a detailed view of the incentives provided to renewable energy in the USA.  The underlying logic of these renewable incentives is that renewables are clean; renewables face hurdles in the market; and incentives are needed to overcome the resulting market failure.  Simply changing these programs to apply to all clean energy sources (i.e., including nuclear power) would provide power incentives for nuclear power and help resolve market failure[3] related to nuclear power.

5.            Reward valuable nuclear power attributes

In addition to the out-of-market revenue for clean nuclear energy, it may be possible to reward nuclear power for other valuable attributes of nuclear power plants that may not be reflected in electricity market prices.  These attributes might include reliability, long operating life, fuel diversity, low land use, system resilience, and other benefits.  Payments for these attributes might help merchant nuclear power plants survive and might even help support investments in new nuclear power projects.

6.            Include full cost of all electricity options

If the full cost of electricity is considered, nuclear looks relatively cheap.

Another approach is to re-think the approach to the electricity industry by requiring all generating types to cover the full cost of emissions, intermittent operation, use of transmission lines, and other factors.  An OECD NEA report on the full costs of electricity[4] discusses this issue.  Putting a carbon tax in place to establish a clear price signal related to carbon emissions might be an important factor part of this.

However, incorporating the full cost of all generation types in formal bid-based electricity markets may be difficult, given their reliance on short-run marginal costs as the basis of generator bids.

Summary

Nuclear power projects are among the largest and most complicated projects in the world.  But nuclear power is also an essential part of a low-carbon or zero-carbon electricity system, providing a unique mix of clean, reliable, and scalable electricity.

Assuming that the market will deliver new nuclear power plants is wishful thinking.  Nuclear power will only be delivered by private investors with a significant role of government. Nuclear power plant development at the scale needed to help with climate change may only be possible as part of a national program – the earlier French nuclear power plant program and the current Chinese nuclear plant program are examples.

These national nuclear power programs allow in-country nuclear power development on a large scale, and also provide the national nuclear industrial companies with advantages in the global nuclear power market.

[1]              The excellent “Nuclear in the States Toolkit” prepared by the ANS Special Committee on Nuclear in the States in 2016 has a comprehensive list of actions that could be used to save existing US merchant nuclear plants from early retirement.

[2]              See https://www.energy.gov/ne/articles/new-doe-report-examines-how-incentives-used-renewables-could-benefit-small-modular

[3]              See NECG Commentary #21

[4]              See https://www.oecd-nea.org/ndd/pubs/2018/7298-full-costs-2018.pdf

PDF version

The post #24 – Government Support appeared first on Nuclear Economics Consulting Group.

The Expert Finance Working Group (EFWG) was convened by the UK Department for Business, Energy and Industrial Strategy (BEIS) in January 2018 to determine key policies and a market framework needed to attract private financing to small reactor projects and to deliver a set of recommendations to Parliament for consideration. NECG Affiliate Amjad Ghori, an expert in nuclear finance, was a core member of the EFWG.

The EFWG Report, “Market Framework for Financing Small Nuclear” was the result of a months-long effort to develop recommendations for the UK Government to take actions to facilitate the development and financing of market-based SMR projects.

NECG Affiliate Amjad Ghori, a core EFWG member, contributed his expertise in energy and nuclear project financing.

The EFWG Report and its recommendations are focused on first-of-a-kind SMR projects needed to establish an SMR industry.

EFWG Report

This short summary of the Report is no substitute for reading the actual Report.  The EFWG’s scope was to assess the prospect of raising private investment for small nuclear projects.

Chapter 2 discusses how clean, safe, and economically attractive small reactors can help deliver the UK’s ambitious Clean Growth Strategy and notes that private sector investments will be needed to do so. However, market failures and a lack of private sector investments require a role for the UK government in delivering first-of-a-kind (FOAK) small nuclear projects and in establishing industry support.

Chapter 3 describes the potential benefits of small nuclear reactors (e.g., lower costs due to modularity and shorter lead times) compared to large nuclear projects.  These benefits would be enhanced with technology and manufacturing capability development.

Chapter 4 notes that technology development, manufacturing capability development, and power project development for small nuclear all require corporate and/or project financing.

Chapter 5 suggests that the risk profile of small nuclear projects should offer improved opportunities to attract investment and finance compared to large nuclear projects.

Chapter 6 presents nine potential financing structures for small nuclear based on global experience with energy projects and includes a discussion of the potential for refinancing.

Chapter 7 presents seven recommendations to HMG:

1. Focus on policies and market frameworks, rather than down-selecting technologies;
2. Work with stakeholders to understand small nuclear risks;
3. Focus on bringing FOAK small nuclear projects to market by 2030;
4. Establish an advanced manufacturing supply chain initiative for small nuclear;
5. Work with nuclear regulators to develop an optimised and flexible approach to the Generic Design Assessment (“GDA”) process for small nuclear projects;
6. Make sites available to FOAK small nuclear projects and de-risk the licensee role for small nuclear projects; and
7. Reduce the cost of capital and share the risks of FOAK small nuclear projects with private investors.

Appendix A describes EFWG members, the process used to develop the report, and the stakeholders that provided evidence.

Appendix B is a discussion by Dr. Giorgio Locatelli of the University of Leeds on how megaprojects (e.g., large nuclear power projects) face issues leading to delays and cost overruns.

Appendix C is a series of detailed risk registers for each of the three phases (i.e., Technology, Manufacturing, and Power Projects) that provide a practical guide for risk allocation.  These are based on generic IAEA risk registers.

Appendix D provides detailed attributes of the nine financing structures described in Chapter 6.

Assessment

The recommendations of this Report, if accepted and implemented by the UK Government, should go a long way to help get the first round of small modular reactors built and to establish an SMR value chain and manufacturing capability in the UK.

Importantly, this Report is another indication that markets alone will not result in a viable nuclear power industry and that a strong role of government is needed for nuclear power. The EFWG Report stops short of recommending a shift to a state-owned nuclear power industry (e.g., as in China, Russia, and other countries), but notes market failure in the nuclear power industry.

According to Amjad Ghori:

“Relying on the market alone to deliver development and financing mechanisms for nuclear projects is not enough.  Government actions on many fronts are needed and essential to enable the development of small nuclear projects and the supporting industry for them.”

The post #23 – EFWG appeared first on Nuclear Economics Consulting Group.