SUPPLY SECURITY AND ELECTRICITY CAPACITY REMUNERATION

GERMAN AND EU FRAMEWORKS


By Attila Máté Kovács, Doctoral School on Safety and Security Sciences, Óbuda University

ELECTRICITY INDUSTRY AND THEORETICAL CONTEXT OF CAPACITY REMUNERATION

A fundamental change has gripped the previously monopolistic electricity generation and supply industry over the past decades. Electricity was seen as a natural monopoly until the 1980s, and in most cases, was privately owned in the United States and publicly owned in Europe.

This changed when Chile, Norway and the UK created competition in the electricity generation sector.

However, achieving the perfect balance between maintaining enough electricity generating capacity to meet peak demand while not paying for a glut of idle power stations is notoriously difficult for any power system. Too much capacity adds unnecessary cost while too little risk blackouts. In developed countries, where power cuts can have economic consequences far greater than paying a little too much for a reliable supply, excess capacity has historically been an acceptable expense. That is no longer the case.

In the US, the three power system operators in the eastern states run arguably the most advanced centralized capacity markets in the world. They aim to procure enough capacity to meet the planning reserve margin “at just and reasonable rates.”

PJM Interconnection, ISO New England and the New York Independent System Operator rely on the crossover point between a supply and a demand curve to set the market price, just as in any market. The demand curve is an administratively calculated estimation of customer need plus a margin over and above the capacity needed to meet peak demand. The supply curve is based on actual offers from power suppliers.

Generators and suppliers in liberalised economies must react to the disciplines of market efficiencies. Uneconomic generation is being pushed out, and sometimes the production unit is retired before it has even paid for itself.

This article aims to explore the economic and regulatory dimensions of this issue. Analyzing market processes and capacity market mechanisms also raises the question of who will make energy investments in such a way that extreme changes in the market model or government policies may make a return on investment impossible.

THEORETIC CONSTRAINTS OF LIBERALISATION AND ACTUAL CONSEQUENCE

Since profit was regulated for private companies, and profitability was not a key objective for public-owned companies, there was no incentive not to spend enough money on investment and maintenance. Such frameworks could ensure that the specified electricity supply standards are never jeopardized motivated by sheer profit maximization. Companies could be given a duty to ensure the network’s safety and ensure sufficient generation capacity. These systems and mechanisms were criticized as inefficient as there was no profit-driven incentive to cut costs: any savings made by the company was passed on to consumers. The liberalized model addresses this issue by making the generation a competitive activity and implementing monopoly network incentive control. Companies can keep cost savings as an extra profit under reward legislation.

A combination of market forces for generation and controlled network performance goals were believed to be sufficient to prevent system quality deterioration. There are serious reasons that this is not going to be the case.

When activities can now be bought and sold regularly in the energy industry, that may easily lead to a ‘take the money and run’ philosophy. For several years, decreasing maintenance may not be reflected in poorer performance, which could have changed the ownership of the facility more than once.

In the early 2000s, for example, in Britain, The Eastern distribution network had five owners in just eight years, while ownership of some power stations changed three or four times in the same period.

FROM BLACKOUTS TO PRICE EXTREMITIES

What makes electricity supply but also the balance of supply and demand so critical? Blackouts of electricity can be serious events that cause human misery and disruption of the economy. Because of human error and extreme weather conditions, there is a chance of blackouts even in the best-run systems. However, it is necessary to establish a safety standard that strikes the right balance between safety and cost and maintains this standard.

The liberalisation of the earlier decades was followed by blackouts, for example, in the summer of 2003. Blackouts affected many OECD countries: Canada and the USA in August, followed by Denmark, the UK and Sweden, and Italy in September 2003 (Council of European Energy Regulators (CEER), 2003). This followed from the massive blackouts in California in 2001, and Auckland, New Zealand in 1998. Also, France, Ireland, Japan, the Netherlands and New Zealand all released official alerts about the likelihood of power cuts during 2003 due to potential power shortages for a variety of reasons. In France and Japan, it was due to nuclear power plant closures (in France because it was difficult to cool the reactors during the hot summer).

The 2003 blackouts and their predecessors included network failures and/or shortages of power. Some of the factors involved are common characteristics. The UK blackout in London was triggered by a local distribution system’s part failures and errors. As for supply’s importance, the UK’s August 9th, 2019, loss of power provides a clear example (RAP, 2019).

Figure 1: Chain of events – 9 August (Regulatory Assistance Project (RAP), 2019).

On 9th August, from around 4:54 pm, there were power cuts in Great Britain, affecting around 1GW (5%) of demand. This loss of power was the automated response to a low-frequency incident (in which the system frequency fell to 48.9Hz or less) due to the near-simultaneous tripping of two power stations, “each associated with” a significant lightning strike on a transmission circuit.

Figure 2: Map of UK loss of load events.

Price extremities in Germany do specifically show the effect and challenge of integrating renewables in the electricity market. In Germany, a new record in renewable energy production was set in May 2016. During spring, sunny and windy weather, the country’s solar, wind and hydroelectric power, and biomass-based energy, pushed electricity consumption and prices up (see Figure 3).

Figure 3: Electricity generation and demand in Germany, 7 to 16 May 2016 (Agora Energiewende).

In many countries around the world, electricity restructuring has been taking place. It has numerous forms in different countries and has been referred to as deregulation, privatization and liberalization. The driving force behind these changes was the desire or the need to:

  • stimulate competitive pressures
  • reduce costs and promote innovation by reducing electricity prices by raising private capital for building power stations to increase
  • redistribute or share ownership, related roles and responsibilities.

There was a tendency to describe these changes as deregulation, although the changed systems and regulations usually had as many rules after restructuring as before. As a result, markets retained former monopolies elements, such as transmission and a powerful regulator with wide-ranging powers.

THE PHENOMENON OF MISSING MONEY1 AND ITS CONSEQUENCES

Those who consider the traditional or liberalized energy market’s efficiency as inadequate are talking about the missing money problem: Power plants do not generate enough profits to cover their capital costs. This problem is due to the short-term price inelasticity of demand, which only leaves room for short-term marginal pricing. Thus, missing money could be described as inadequate profitability at peak times (Joskow, 2006). But could the “missing money” phenomenon be addressed with further regulation? Or addressing the problem of missing money lead to jeopardizing the market itself (Newbery, 1989)?

In liberalized markets, prices may influence producers’ willingness to enter the market. Still, supply reliability and many other parameters also depend on the skill and price sensitivity of the consumer. If it is realistic to assume that market prices will cover their extra costs, producers will only enter the market in a liberalized market.

The prices are defined by supply and demand in the power sector. Electricity producers bid certain amounts of power for a certain price on the German day-ahead power exchange EPEX Spot2 while buyers lodge in the order book how much energy they are willing to buy at a given price. It has to be done every day by noon the next day. Two curves can be drawn when positioning the bids for sale and purchase in order. The point where their trajectories meet targets the price of market-clearing – the price paid for all successful offers (see Figure 4).

Figure 4: Merit order curve (Next-Kraftwerke).

Higher variable cost gas producers are marginalized and will only be able to sell if cheaper producers cannot meet demand. Until recently, the electricity sector has typically developed an “energy-only market”, the players mainly supply and buy energy (MWh), and there is no separate capacity (MW) product3.

The European Commission has worked out a compromise: Capacity mechanisms can be used, but only if the requirement for this is substantiated by resource adequacy studies using a transparent methodology, and when other market-conform measures cannot be achieved.

In many European countries, there is a need to introduce a financing mechanism to support peak power plant investments deemed necessary for system security and the availability of existing power plant capacity.

Not surprisingly, evaluating the capacity reward mechanism largely depends on how it deals with the missing money. France and Germany’s positions differ significantly (including public authorities, academic institutions, private companies).

In practice, not all markets fulfill the theoretical ideal, and different forms of regulatory and administrative intervention may be required. In a given market situation, TSOs will choose the lowest EUR / MWh offer. Such supply can be provided by weather-dependent producers (whose variable costs are negligible), as well as by traditional coal and nuclear producers with low variable prices (Székffy, June 2014). However, it is also clear that it is complex to shape the curves to achieve long-term capacity adequacy at just and reasonable rates.

Figure 5: (European Commission4, 2016).

For obvious and partly understandable reasons, utilities look for a way out and signal difficulties. Not only do they have to look at how their assets become loss-making, but also have to survive overall profitability decrease affected by lower cash flow from profitable assets.

Yet, the argument for implementing CRMs may not always seem compelling, as EU generation capacity has increased as a result of growth in renewable energy sources (and a decline in conventional power). However, electricity demand and wholesale prices have been steadily declining since 2011.

On the other hand, ‘safety of supply’ has often been used as a catch-all term as a convenient label for protectionist MS policies to cover various support measures for ailing businesses.

CONCLUSIONS

In the increasingly competitive – yet also regulated – electricity markets, companies and even regulators all face a new and unfamiliar environment, challenges and questions like the below:

  • In order to meet growing demand, how much new capacity should a generating company build?
  • To balance market share and short-term competitiveness, at what cost will generators sell their generating plants on the market?
  • How can a regulator ensure competitive prices prevail in the market while retaining ample opportunities for a new entry?

Apart from raising further questions, there may be actual actions, issues or routes for the future to consider:

  • Regulatory systems and frameworks need to be in a place that can restrict market forces and competitive concerns by referring to the public interest (i.e., not just competition policy), even if restricting company management.
  • Transmission providers should be subject to strict safety and reliability requirements, implemented by a public interest regulatory authority and/or public grid ownership.
  • As part of their permit, regulators should impose strict requirements on distribution companies: requiring businesses to show how their future investment and maintenance plans can ensure reliability and tracking these programs to ensure compliance.
  • A requirement to hire and train a skilled workforce to carry out the work or a ban on contracting out core functions, including network maintenance and customer service
  • Transmission and transmission legislation should be based on open and public processes to promote and resolve representations from shareholders and citizens’ groups.
  • Assessment and re-evaluation of cross-border transmission lines for power trading should be carried out, also considering the public interest. The sheer facilitation of trading itself should not be a justification for such investments.

As for capacity remuneration, the dilemma is apparent. Ceteris paribus, free movement of prices can serve to cover power plant costs, which should increase in times of scarcity (assuming a rolling shutdown, prices can be extremely high). At the same time, these events provide price signals for investors to make their investment decisions. This process and adaptation can be disrupted by artificial interventions or anomalies in the market, with their effects preventing the achievement of theoretical market prices. In this way, large state-subsidized renewable energy units can remain competitive, while, for example, the costs of lignite power plants increase due to the CO2 quota.

And without regional and fundamental changes (that tend to take place after crises), but with all the regulatory action and concepts, it can still be said that if a government decides to eliminate the capacity market, it will no longer be.

While an electricity market, supply and demand will still exist. The further the industry and stakeholders get in research and development, shared responsibilities and cooperation, the better prospects to build a sustainable and robust electricity system.■

BIBLIOGRAPHY

REFERENCES

  1. The term was originally coined by American economists in the 1990s and is still analyzing the German situation (Cramton & Ockenfels, A., 2011).
  2. Source of trading information: https://www.epexspot.com/en
  3. Capacity mechanisms are measures taken within the competence of the Member States that guarantee the desired level of security of supply by paying for the availability of generation capacities.
  4. Source map: Proposal for a Directive of the European Parliament and the Council on common rules for the internal market in electricity (updated according to 2017-2018 developments)

ABOUT THE AUTHOR

With two MAs in Economics and Energy, Attila Máté Kovács now pursues a PhD at Óbuda University Doctoral School of Safety and Security Sciences, while working as an IT security consultant at Cyber.services. He also deepened and now uses his knowledge in two other proficiency fields of his interests: Artificial Intelligence and Machine Learning. He is a Certified Ethical Hacker and PRINCE2 Practitioner. At the start of his career, he worked as a strategy consultant at Roland Berger Strategy Consultants and Accenture. He then worked as an IT strategy expert at energy and aviation companies before joining Cyber Services Plc. His research interests include critical infrastructure cyber security, cyber forensics, cyber-physical and embedded systems, ATM-UTM transition air traffic management, unmanned aerial vehicles, energy economics and models. While capacity mechanisms may seem abstract, studying events like the August 2019 UK blackout, he believes that supply mechanisms do affect economies and everyday life.


Download the article as a PDF: Attila Máté Kovács article – CIP Review online – September 2020


Publication date – September 2020