News

The ITRE Committee organises on April 24 a public hearing on the reform of the Electricity Market Design that was proposed by the Commission on 14 March. The proposals aim to accelerate renewable generation and the phase-out of fossil gas, make consumer bills less dependent on volatile fossil fuel prices, better protect consumers from future price spikes and potential market manipulation, and make the EU’s industry clean and more competitive.

The participating experts are:

• Konrad Purchała, Managing Director for System Management in PSE
• Natalia Fabra, Professor of Economics at Universidad Carlos III de Madrid
• Georg Zachmann, Senior Fellow at BruegelProf. Jorge Vasconcelos, Chairman of NEWES
• Jaume Loffredo, Senior Energy Policy Officer & Energy Team Leader of BEUC

Electricity Market Design: Views from European Economists

Europe has faced – and still faces – an unprecedented energy crisis that has translated into record-high gas and electricity prices, further propagating through the entire European economy. The rise in energy costs has been the main driver of inflation, whose EU average reached 11.5% in October 2022, pushing the ECB to increase interest rates. Inflation, coupled with the hike in interest rates, has reduced European households’ disposable income and purchasing power, put the competitiveness of European industry at risk, and forced governments to implement – subject to their asymmetric fiscal capabilities – costly support mechanisms to mitigate some of the economic and social consequences of the energy crisis.

These events have put electricity market design under the spotlight. The question is not only how to avoid the energy crisis from repeating itself in the future, but also how to promote low-carbon investments at the scale and speed necessary to decarbonize our economies while preserving security of supply. Following the words of the President of the European Commission in her State of the European Union Speech (“we will do a deep and comprehensive reform of the electricity market”), the shared view now is that these endeavors call for an electricity market reform. The question is: in which direction?

In this context, the European Commission has launched a public consultation on the electricity market reform. As European economists, we would like to share our views regarding key issues in the debate – space and time limitations prevent us from offering a broader discussion on all matters.

Short-run electricity markets should be preserved

Overall, we support the consensus on preserving short-run electricity markets. These markets provide an indispensable tool to achieve efficiency in production and provide the right signals for efficient consumption. In particular, short-run prices are instrumental in guiding the efficient operation of some generation assets (including hydro, energy storage, and demand side flexibility, to name just three). However, we also share the view that reliance on short-run markets alone is inadequate as they are overly volatile, they do not reflect the average costs of the various generation technologies, and they fail to provide efficient market signals for long-run investments, both on the supply side (e.g., investments in renewable energies) as well as on the demand side (e.g., investments in electrification by industry). A priority of market design should be to facilitate healthy long-run contracting arrangements capable of addressing those concerns.

Long-term contracting should be promoted

At the core of the electricity market reform rests the need to ensure sufficient long-term contract coverage of producers and consumers at competitive prices. Long-term contracts protecting producers and consumers against cost and revenue shocks should be designed to also reduce electricity prices while strengthening the ability and incentives for participation in short-term markets. If designed cleverly, long-term contracting will enhance the functioning of short-term markets by (i) reducing risks related to regulatory interventions or technological breakthroughs, (ii) limiting incentives for exercising market power, and (iii) allowing for more entry and broader participation.

Despite the consensus on the need to strengthen long-term contracting, how to achieve this goal is intensely discussed. Two main options are: (i) bilateral private contracts, known in the electricity jargon as Power Purchasing Agreements (PPAs); and (ii) auctions for contracts for differences (CfDs) run and underwritten by regulators on behalf of consumers. Beyond the current discussions in electricity markets, economists have discussed the merits and demerits of these two market designs for a long time. And despite the potential trade-offs, one conclusion should be clear: it is incorrect to believe that (i) only PPAs are a market-based solution, capable of delivering the necessary scale of investment in the coming years, and that (ii) CfDs involve state support and should only be used when the market fails. These misconceptions, implicit in the European Commission’s public consultation document, risk biasing the assessment of how to organize long-term contracting in electricity markets.

In the context of electricity markets, we consider it important to keep in mind the following aspects in any comparison of PPAs versus CfDs:

PPAs alone are not fit to deliver low-carbon investments at the scale and speed needed

PPAs between generators and large energy-intensive firms have allowed for a first set of renewable investments to be pursued in several EU member states. This has notably been the case in Spain and the Scandinavian countries, where 13-20% of the total contracted capacity is contracted through PPAs. Efforts should be devoted to understanding why PPAs exist in some countries and not in others, and assessing the price impacts of PPAs on the end-users and not just their total volume. In any event, it is unlikely that PPAs will deliver the scale of renewable energy investments at the speed necessary to achieve the energy security and climate objectives agreed upon at the EU and Member State levels. Retail companies cannot underwrite sufficient volumes of PPAs because of the considerable uncertainty about future prices and quantities. Should it turn out that long-term PPA prices exceed shorter-term wholesale prices, retail competition would allow consumers to switch to other retailers that can afford to offer lower prices. Likewise, electricity-intensive industrial consumers cannot underwrite PPAs at a significant scale because their value in companies’ books will vary with changes in expectations of power prices to levels that, in some cases, would likely exceed the value of the companies themselves. Furthermore, should short-run electricity pricesfall below long-term contract prices, industrial players tied to PPAs would lose competitiveness viz à viz other industrial competitors who procure their power at spot market prices.

PPAs involve significant counterparty risks and are only suitable for large market players

For project developers, PPAs for long durations involve significant counterparty risks. First, private buyers – typically large energy-intensive companies and energy retailers – find it difficult, if not impossible, to guarantee that they will keep consuming the committed amounts of power in 10 to 20 years, for which a necessary condition is being active in the market by then. To avoid the temptation to renege from those PPAs should future electricity prices turn out lower than anticipated, PPAs need to be secured with corporate guarantees, which are costly and might create liquidity problems. The counterparty risks involved in PPAs increase financing costs and translate into substantial increases in the levelized costs of energy.

To date, PPAs have primarily been underwritten by publicly owned companies, financially strong energy-intensive companies for a small share of their total energy needs, or large companies for which energy costs are a minor cost component, such as major IT companies. There is no evidence that the industry can scale up the share of energy contracted under long-term PPAs to the level of renewable investment envisaged for the next decade. Furthermore, the complexity of PPA contracts and the uncertainty of coordinating consortia to underwrite PPAs at the demand side further limit the ability of smaller players to participate in these contracts. They thus create a bias benefiting larger players and therefore risk participation, competition, and further development of project pipelines by smaller actors.

Markets for PPAs are subject to competitive concerns, and the PPA prices are not necessarily passed on to the end-users

Markets for PPAs are opaque because the private contracts between the parties remain confidential. Opacity contributes to weakening competition, creates barriers to entry for new players, and weakens the signal for long-run investments. Furthermore, when energy retailers sign PPAs, there is no guarantee that they will share the potential savings achieved through PPAs with their customers. The reason is that energy retailers will price electricity at the resulting equilibrium price in the retail market, regardless of the price at which they buy electricity upstream. Lastly, PPAs risk draining liquidity from short-term energy markets, negatively affecting competition and productive efficiency, unless some provisions are put in place to guarantee that energy subject to PPAs is also offered in the wholesale market.

Benefits of PPAs and scope for improvement

Despite the above concerns, PPAs can play a role in various dimensions. First, in the absence of other long-term contracting options, PPAs have provided a contracting mechanism for firms that can credibly sign long-term contracts for a share of their energy needs. Second, they may provide additional contracting flexibility that can be tailored to the specific needs that counterparties might have, including the desire of industrial players to hedge their energy prices when planning their decarbonization electrification strategies. Third, PPAs will likely provide an instrument for investments in lifetime extension for existing renewable assets.

However, the problems outlined above suggest scope for improvement. For instance, to avoid opacity, firms should be required to make the contract terms publicly available through a central registry. Also, auctions of standardized PPAs should be favored over bilateral negotiations to enhance competition.

In any event, PPAs alone will be insufficient to unlock the needed investments and are inadequate for the vast part of energy consumers who cannot sign or benefit from those contracts. Furthermore, counterparty risks and the temptation to renege from PPAs seem unavoidable – and we do not recommend using public guarantees to overcome this, as this might require large amounts of public money while giving rise to moral hazard problems. Crowing out of PPAs by CfDs, if that were to happen, should not be a concern – the objective is not to have PPAs per se but rather that the overall volume of long-term contracting is achieved at competitive prices for end-users.

Regulatory-backed auctions for CfDs do not face these limitations

Publicly-backed auctions for CfDs do not face these limitations and thus offer a credible investment perspective for delivering the required volumes of renewable energy projects, which have already been set both nationally as well as at the European level. Regulatory-backed contracts are therefore also essential to unlock the investments into an EU supply chain of renewable energies’ manufacturing capacity. A CfD model has already been successfully implemented in various EU countries, achieving significant participation in the auctions and large price reductions. In particular:

• Governments can auction the volume of CfDs required to meet energy needs domestically and through joint renewable tenders of several countries. This creates a credible investment framework for investments in renewable projects as well as in the whole value chain. Levelised costs of renewable energy could decline significantly compared to PPA structures thanks to reduced counterparty risk.
• Auctions are effective mechanisms for extracting investors’ information about their actual costs if appropriately designed. Competition through auctions will thus allow consumers to benefit from the lower costs of renewable investments. Efforts should be put into the design of these auctions to promote ample participation and competitive outcomes.
• In particular, the CfD auctions can be designed to reward system-friendly production profiles to ensure the alignment of today’s investment choices with the needs of the transforming energy system. They can also be designed to avoid large inframarginal rents, thus contributing to an affordable and competitive energy supply. Related to this, the interplay with PPAs needs to be well designed so as to avoid the projects at the best resource locations cherry-picking PPA structures, which would result in higher costs for consumers.

Government (agencies) can pool these underwritten CfDs and pass them to final consumers (or retail companies on their behalf) in ways that do not distort the short-run price signals or 5 retail competition. Thus, consumers can be hedged against wholesale price volatility while they remain incentivized to hedge (and realize their own flexibility potentials). We recommend allocating access to the CfD prices independently of current consumption to ensure marginal incentives for energy efficiency and investments in flexibility are maintained. For instance, for households, the allocation could be conditional on demographics (family size, income, climate zone) to address distributional concerns and enhance acceptance by the local communities. Each Member State could implement its own procedures depending on its country’s realities. However, all Member States should ensure that the mechanism is transparent, easy to comprehend, and passed through to final consumers.

As an additional benefit of regulatory-backed CfDs, a simplified and stable contracting environment can ease the burden on project developers. Along these lines, the permitting process for renewable installations can be difficult and time-consuming, and more public resources should be devoted to facilitating it.

Limits on inframarginal generators should be maintained

Beyond the debate on long-term contracting, a contentious issue is whether to limit the revenues of the existing inframarginal generators (nuclear, hydro, and renewables). As the President of the European Commission acknowledged, these plants “are making in these times – because they have low costs, but they have high prices on the market – enormous revenues…revenues they never dreamt of; and revenues they cannot reinvest to that extent. These revenues do not reflect their production costs.”

We believe some form of revenue limitations on the inframarginal generators should be maintained. These measures, which were put in place under extreme conditions, should be embraced as a coordination success in moments of critical tension. Given that the market will probably experience extreme conditions in the future, and the challenges experienced will repeat, it is best to retain a safety valve. Having a pre-defined mechanism in place will avoid all the challenges emerging from the interaction with pre-existing contracts and the turmoil observed during the energy crisis, during which governments had to make quick decisions to limit the burden of energy costs to businesses and households while assuming substantial debt.

There are some economic principles that these revenue limitations should respect. First, revenue limitations should be implemented without distorting the marginal signal for the relevant price ranges in the wholesale market. This can be achieved by a number of approaches, including a constant rate per unit of output reduction in revenues or the dispatch of strategic reserves once price levels reach a pre-agreed price level. This can be considered to replicate approaches common in international markets that trigger those mechanisms only with sustained high prices, exempting short-lived price spikes. Second, the limit must be high enough to be considered “unexpected” under business-as-usual conditions. This will ensure that there are no investment distortions. As a notable exception, legacy technologies, such as large hydro projects and nuclear plants built prior to liberalization, have been developed as public projects and are not subject to concerns about investment incentives. Member States could implement stricter revenue limits for these legacy plants without impacting the efficiency of the market.

Finally, keeping inframarginal revenue limits can also mitigate the contracting risk associated with sustained high marginal prices like the ones we have observed during the energy crisis. These policies reduce the extent to which firms may fail to comply with or even profit from breaching their contracts and foster a healthier contracting market. They also contribute to making the auctions for CfDs more competitive to the extent that the outside option of selling directly in the short-run market becomes less attractive. Last, it is important to note that these measures would only be triggered under episodes of sustained high prices or would apply to legacy plants. Hence, they would not alter the legitimate expectations of the plant owners and should thus not be considered expropriatory.

Conclusion

In sum, we welcome the European Commission’s initiative to open the debate on the electricity market reform. Europe’s industry and households cannot afford to pay high and volatile electricity prices much longer. The new electricity market arrangements should seek the two-fold objective of (i) providing market resilience in the event of future crises to electricity generation systems (e.g., due to increases in fossil fuel prices, droughts, or nuclear outages, among others) and (ii) promoting decarbonization at least cost and risks for firms and consumers.

To ensure a healthy long-term contracting environment, we call for caution regarding reliance on PPAs alone. On their own, PPAs are not fit to deliver low-carbon investments at the necessary speed and scale and are unlikely to benefit all consumers, particularly households and small and medium-sized companies. On the contrary, we see potential in regulatory-backed auctions of contracts for differences, which under adequate provisions, can co-exist with PPAs. This approach would help secure the needed investments, foster stronger competition among entrants, and drive down the costs of the investments through reduced counterparty risk, ultimately benefiting all consumers through lower electricity prices. As a remaining challenge for market design, it still needs to be defined how the two instruments should interplay.

Long-term contracts should be designed to strengthen the good functioning of short-run energy markets, which play a key role in promoting productive efficiency and flexibility. As a safety valve against future turmoil, we recommend keeping and improving the mechanisms to avoid inframarginal rents from escalating at huge societal costs.

A reform in this direction would be the best antidote against the fears of European deindustrialization and a big push to the European ambition of having a say in the Green battle.

Signatories:

Stefan Ambec (Toulouse School of Economics, France)

Albert Banal (Universitat Pompeu Fabra, Spain)

Estelle Cantillon (Université Libre de Bruxelles, Belgium)

Claude Crampes (Toulouse School of Economics, France)

Anna Creti (University Paris Dauphine, France)

Francesco Decarolis (Bocconi University, Italy)

Natalia Fabra (Carlos III University and EnergyEcoLab, Spain)

Reyer Gerlagh (Tilburg University, Netherlands)

Karsten Kneuhoff (DIW, Germany)

Camille Landais (London School of Economics, UK)

Matti Liski (Aalto University, Finland)

Gerard Llobet (CEMFI, Spain)

David Newbery (Cambridge University, UK)

Michele Polo (Bocconi University, Italy)

Mar Reguant (Barcelona School of Economics and Northwestern University, Spain)

Sebastian Schwenen (Technical University of Munich, Germany)

Iivo Vehviläinen (Aalto University, Finland)

On March 24th, 2023, we will organize the final workshop of the project MIMA-CM, funded by the regional government of Madrid and the European Social Fund between January 2020 and April 2023 (H2019/HUM-5859). It will take place at CEMFI.

The aim of the project is to study policies to foster innovation, make progress towards the energy transition, and promote competition in key sectors such as the power sector and the pharmaceutical sector.

More information here.

Energy markets in the last 18 months have been characterized by significant price increases, threats to security of supply, and the need for mitigation policies and structural reforms. IGIER at Bocconi University has organized a workshop entitled “Energy markets in turmoil: causes and policy options”. Natalia Fabra will be the keynote speaker, Clara Poletti (ARERA), and Francesco De Carolis (Bocconi University) will act as discussants.

Attempts to reduce carbon emissions and promote economic growth through renewable investments face a range of obstacles worldwide. This column examines one of the most confounding of these obstacles – opposition from local communities. Why do residents oppose renewable investments, even those promising socioeconomic benefits such as new jobs? Using data from across Spain, the authors find that new jobs from renewable investments do not always remain in the municipalities where the ventures are built. Public policies should therefore ensure that benefits from renewable investments are shared with the hosting communities.

A technological revolution has driven the costs of investing in renewable energies to record lows. Over the last decade, the costs of investing in solar photovoltaics and onshore wind have fallen by 88% and 68%, respectively (IRENA 2022, Newberry 2018). These cost reductions have fostered a massive roll-out of renewable energy investments around the globe, making it easier to reduce fossil fuel consumption. However, an unexpected obstacle has emerged: opposition from the local communities that host the investments. This movement, known as NIMBY (‘not in my backyard’), is responsible for blocking solar and wind developments globally.

Several papers have analysed the costs imposed by renewable energy projects on the hosting communities, including their adverse effects on land conservation and biodiversity or the crowding out of economic activities such as agriculture or tourism (e.g. Germeshausen et al. 2022). However, little attention has been devoted to understanding the other side of the equation: local benefits. Do hosting communities oppose renewable investments because of the local costs, or because they do not benefit enough to offset those costs? It is widely recognized that renewable energies bring about socioeconomic benefits. Indeed, post-pandemic recovery plans rely on green investments as a lever for economic growth and employment. If those benefits are real, but local residents still oppose the investments, does that mean the local benefits are not enough to compensate for the costs?

In recent work (Fabra et al. 2022), we use local employment and unemployment impacts as proxies for the local economic benefits of renewable investments. We exploit variations in the timing and size of investment projects across more than 3,200 Spanish municipalities using 13 years of monthly data that witnessed two major investment waves (2007–2020). We use detailed data on individual renewable projects, including their location, technology, and start-up date. These data are combined with employment and unemployment data at the municipal level. Whereas employment data capture the number of jobs by local firms, unemployment data reflect the number of local residents without a job. Combining these data sources provides a rich picture of the heterogenous local labour market effects caused by renewable investments. Methodologically, as far as we are aware, our work is the first application of Dube et al. (2022), who propose a new estimator for staggered differences-in-differences analysis that extends the local projections approach (Jordá 2005) with clean controls.

Importantly, we find significant differences in the local job multipliers across renewable technologies. Whereas investment in solar photovoltaics has sizeable multipliers, investment in wind triggers no statistically or economically significant local job creation. The mechanisms that explain these differences are related to the types of tasks and skills required to carry out the projects. In the case of wind, investments are front-loaded and not necessarily local, as high-skilled workers are required to carry out the projects, which they often do from elsewhere. Solar investments require less specialised skills, allowing the project developers to hire workers locally. Furthermore, the construction of solar farms, which has a strong local component, bears a higher weight in the project’s total cost. Consistent with this, we also find that the labour market effects of solar investments concentrate primarily during the construction phase and become milder during the maintenance phase. These findings align with the International Renewable Energy Agency (IRENA)’s 2021 assessment: “The integration of local content and local employment remains a challenge, particularly in wind energy”.

Figure 1 illustrates the employment effects across technologies and periods. The x-axis reflects the number of months before or after the start-up date (marked by a solid red line). By that date, the plant must be ready to produce electricity, so treatment must have begun approximately 24 months before, when construction is expected to have started (marked by a dashed red line). The y-axis shows the value of the job multipliers per MW invested (a similar pattern is found per million euros invested).

In the case of solar investments, multipliers become positive and significant approximately 22 months before the start-up date, consistent with the start of construction, and peak at around seven months before that date, when the major construction work is finished. Later multipliers decrease but only partially vanish, reflecting labour needs during the maintenance phase. The average local multiplier one year before the end of construction is 2.5 workers/MW (or 0.8 workers/million € invested) and 1.5 workers/MW during the maintenance phase (or 0.2 workers/million €). These local multipliers are in line with those found for fracking in the US (Feyrer et al. 2017). In the case of wind, the local employment multipliers are not different from zero, during both the construction and maintenance phases. Using a more standard event-study design delivers broadly similar results.

Figure 1 Local employment effects of solar and wind investments

Notes: These figures show the effects of investing 1 MW on employment by firms located at the municipalities where the investment occurs in the period February 2006-January 2018, h months before or after the start-up date (marked with a vertical red line). Panel (a) shows the results for solar investments and panel (b) for wind investments. Error bands depict the 95% confidence interval. Standard errors are clustered at the municipality level.

As seen in Figure 2, the effects on employment tend to be larger than those on unemployment, suggesting that local firms hire workers in other municipalities or counties to carry out the projects. This is consistent with difficulties in finding skilled workers in the rural municipalities where most of the projects are located. The local multipliers are well below those found for other infrastructure projects in Spain (Alloza and Sanz 2021). The weak unemployment multipliers also reflect that the labour market effects are mostly confined to sectors directly linked to the construction or maintenance of the plants, in line with our sector-level analysis. Interestingly, in the case of solar, there is a slight surge after the start-up date in the number of unemployed workers who were previously employed in the construction sector. This is true even relative to the pre-construction period. This finding is consistent with the project attracting new residents to work on the plant’s construction who become unemployed once construction ends.

Figure 2 Local unemployment effects of solar and wind investments

Notes: These figures show the effects of investing 1 MW on unemployment by residents in the municipality where the investment occurs in the period June 2008-January 2018, h months before or after the start-up date (marked with a vertical red line). Panel (a) shows the results for solar investments, and panel (b) for wind investments. Error bands depict the 95% confidence interval. Standard errors are clustered at the municipality level.

The relatively small magnitude of the local effects, particularly in wind investments, does not mean that renewable investments do not create jobs on a broader scale. Indeed, it is plausible that a significant fraction of the employment benefits accrue away from the municipalities where the investments occur. However, since the opposition of local communities may become a bottleneck for the broader deployment of renewable energies, it is fair and efficient to distribute the gains from the renewable investments within the hosting municipalities. Promoting local energy communities so that residents have a stake in the new projects; reducing the electricity price for local residents; increasing the local taxes paid by renewable investors; prioritising grid access to those projects that promise greater local benefits… These and other options should be considered to obtain the social acceptance of renewable projects among local communities, which is necessary for their broad adoption.

This article was published at VoxEU on January 5, 2023

“The current electricity market design is not doing justice to consumers anymore. They should reap the benefits of low-cost renewables. So, we have to decouple the dominant influence of gas on the price of electricity. This is why we will do a deep and comprehensive reform of the electricity market.” These words were pronounced by the President of the European Commission in her State of the European Union speech in September 2022 (von der Leyen, 2022). By then, gas and electricity prices had reached record highs (Figure 1), with growing concerns about gas shortages during winter (Martin & Weder di Mauro, 2022). The rise in energy costs contributed to double-digit inflation in the Euro area (Eurostat, 2022), leading to the highest-ever increase in interest rates by the European Central Bank (Dieppe & Brignone, 2022).

Four months later, the European Commission is about to open a public consultation on the electricity market reform they are working on (European Commission, 2022). In this column, I shed light on what I think should be the building blocks of this reform. The interested reader can find the full details of the proposed electricity market architecture in Fabra (2022).

Figure 1: Electricity prices in European wholesale electricity markets

Source: Red Eléctrica de España.

Objectives and Building Blocks of the New Market Architecture

The reform should lead to efficient and equitable electricity market outcomes. In the short run, achieving productive efficiency requires that demand is met, at every moment in time, by the plants with the lowest marginal costs. In the long run, investments should efficiently take place at the right scale and locations. In particular, investments in low-carbon technologies should be promoted to meet future electricity needs without compromising security of supply. For equity, households and businesses should fully benefit from the lower costs of these technologies, which further helps promote electrification to decarbonize hard-to-abate emissions in other sectors.

Figure 2: The proposed market architecture

These objectives can be reconciled by combining short-term energy markets— which provide short-run signals for efficient generation and consumption—with long-term contracts—which facilitate efficient investments in generation while adjusting their profitability through competitive forces (Figure 2). These two pillars of the proposed electricity market architecture complement each other and interact in several ways. In more detail:

• A well-functioning short-term market:

Electricity demand and supply change at high frequency. Hence, productive efficiency must rely on electricity markets that clear close to real-time, very similar to those operating today in Europe. However, certain design elements can be put forward to improve their performance. Importantly, compulsory participation in these markets (as in the original UK market design) would contribute toward greater liquidity and transparency without preventing the market participants from entering into financial contracts with third parties. Long-term contracts, as described below, would further prevent the short-run price signal from being distorted by market power (Fabra and Imelda, 2022).

• Efficient and equitable long-term contracts for all consumers:

Electricity generation assets are highly capital-intensive and long-lived, often giving rise to various positive and negative externalities (e.g., affecting learning economies, security of supply, or the environment, to name just a few). This suggests that achieving long-term efficiency requires some form of long-term contracting, with the regulator playing an active role in deciding the investments’ scale and technologies. Furthermore, for outcomes to be equitable, regulators must resort to mechanisms allowing electricity prices to reflect the average costs of the investments in ways compatible with facing firms and consumers to short-run prices. In my view, adequate long-term contracting is missing from current electricity markets, and addressing this should be the focus of our efforts. How exactly should long-run contracts be incorporated into the market architecture?

Designing Long-term Contracts

In line with other economists (see Newbery 2022, Roques and Finon, 2002, Kröger et al., 2022, among others), I advocate for developing a system of long-term contracts between the regulator and the generators. Reliance on long-term contracts allows derisking the investments, effectively allowing for an efficient transfer of risk—from the more risk-averse side (i.e., the private investors) to the less risk-averse side (i.e., the regulator on behalf of all consumers). This approach facilitates generators’ access to cheaper capital, opening the market to competitors that would otherwise not be able to finance the investments. Competition for these contracts through auctions organized by the regulator would pass on this efficiency gain to consumers, who would also be hedged against excessive price volatility.

The design of long-term contracts should differ across technologies depending on their flexibility to respond to short-run price signals. These contracts can be designed so as to enhance firms’ efficient behavior in the short-term market. For instance, preserving full-price exposure is paramount for the efficient operation of storable resources, including hydropower, which should be used when they are most valuable. On the contrary, exposing wind or solar plants to short-run prices brings limited benefits, given that their output is intermittent and exogenously given by weather conditions.

An important economic principle should be kept in mind throughout: exposing producers to short-run price signals is compatible with decoupling their average payments from those prices. To see this, consider the design of contracts-for-differences (CfDs). Under these contracts, producers sell their output in the short-term market and then pay/receive the difference between a ‘reference price’ and the contract’s strike price. Setting the ‘reference price’ equal to the short-term price is equivalent to a fixed price contract with no price exposure and no price risk. Departing from this allows for striking the right balance between the benefits of price exposure and the costs of increasing investors’ risks, a trade-off that depends on the technologies’ characteristics.

For instance, for hydropower plants, setting the ‘reference price’ at the annual average market price effectively provides a bonus for producing at peak times or a penalty for producing at off-peak times (Figure 3). For intermittent renewables, setting the ‘reference price’ at the monthly average price captured by plants of the same technology incentivizes them to locate at sites where the availability of solar irradiation or wind is positively correlated with market prices, contributing to reducing the system’s costs. In both cases, marginal incentives are preserved while their profitability is adjusted through the choice of the strike price. Setting the strike price through auctions before the investments have been made contributes to achieving cost-reflective electricity prices.

Figure 3: Flexibility bonus/penalty implicit in the contracts for differences for hydropower plants

However, sufficient participation in the auction is needed for competitive forces to deliver a fair rate of return. Incentivizing firms to participate in the auction requires that the outside option of selling directly to the short-term market is not feasible or not too attractive. Once renewables are massively deployed, the short-term market prices captured by renewables will converge towards their (almost zero) marginal costs, i.e., below their average costs. Hence, entry outside the auction will not be attractive even if feasible. Until then, participation in the auction could be promoted by limiting (at a reasonable level) the maximum price that renewables can obtain in short-term markets – not just as a crisis instrument but as a permanent market feature. Since renewables have low marginal costs, such a cap would not distort their efficient operation.

For existing plants, competition to enter the market is simply not possible. Two options to guarantee equitable outcomes are to introduce technology-specific caps or to regulate their strike prices in a cost-reflective manner. No doubt, this will require political will. However, the economic, social, and political costs of not addressing the large windfalls made by these plants are not less challenging.

Last, the characteristics of gas plants, storage, and demand response facilities suggest they should be fully exposed to short-term market prices. Yet, to overcome their missing money problem (Joskow, 2008) – in essence, short-term market prices do not allow them to recover their investment costs – they should receive capacity payments – not necessarily technology-neutral as they are nowadays (Fabra and Montero, 2022). In the case of gas plants, capacity payments should be combined with commodity-indexed price caps (the so-called reliability options) to prevent them from exercising market power when they are pivotal.

Contracting with the regulator, or bilaterally?

One recurring question in the debate is whether regulators should be the counterparty of the long-term contracts or whether such contracts should be freely signed bilaterally between generators and retailers (the so-called PPAs), with no public intervention. My view is that the latter are not substitutes for the former. We have seen this already: nothing prevents PPAs from being signed, yet several market failures have led to scarce and excessively short PPA contracting (May et al., 2022). Furthermore, even if large energy retailers manage to secure low wholesale prices through PPAs, imperfect competition in the retail market often implies that such prices are not passed on to the final consumers. In contrast, regulators can commit for sufficiently long periods compatible with the recovery of the investments. This would substantially reduce counterparty risk, which is instrumental in lowering the costs of procuring renewable energy (Ryan, 202). Furthermore, a system of regulator-backed long-term contracts would guarantee that all consumers – regardless of their bargaining powers – would benefit equally from the reduced counterparty risk and the enhanced bargaining power of the regulator acting as a large buyer.

Last, even if desirable, increasing the liquidity of forward markets is not a substitute for these regulator-backed long-term contracts either. The prices of forward contracts tend to converge to the expected short-term market prices over the same period, thus reducing price volatility but not the price level.

Conclusions

Europe must take advantage of this opportunity to redesign an outdated electricity market design, which threatens the region’s economic, social and environmental objectives. Changing the electricity market design without significantly affecting the outcomes would be a lost opportunity. The risk of Plus ça change, plus c’est la même chose…is not negligible. In my proposal, I argue that it is feasible to redesign electricity markets to make them more robust to the current and future energy crises while simultaneously achieving carbon abatement goals at least cost for consumers and society. Power markets can be a powerful source of welfare for the whole economy, just as long as we design them right.

We are recruiting one Postdoctoral Researcher with a PhD in Economics or Finance.

The candidate should have an outstanding commitment to research, as well as prior research experience in the areas of Energy and Environmental Economics and/or Empirical Industrial Organization. The position can be filled for one to two years, starting September 2023.

The Economics Department at Universidad Carlos III de Madrid has strong international ties, a widely recognized graduate school, and has been awarded special support as a Center of Excellence by the Spanish government.

Duties: successful candidates are expected to
• contribute to the activities of the research group in the form of research assistance and joint research comparable to a standard teaching load
• participate in the activities of the research group (seminars, workshops, lunch meetings)
• further their own research agenda in the area of energy and environmental economics and sustainable finance
• no teaching duties involved

Requirements: applicants should
• hold a PhD in Economics or Finance (or be close to completing it) from a highly-ranked university
• have excellent qualifications, as well as outstanding own research; focus on empirical tools and programming is highly welcome
• a Finance background is also welcome

Applications should include a resume, at least two letters of recommendation, and at least one recent research paper. Interviews of short-listed candidates will happen in January-February. The review of applications will continue until the position is filled.

Applications should be sent to energyecolab@gmail.com with the subject POST DOC.

Further details are available upon request from the Principal Investigator, Natalia Fabra (natalia.fabra@uc3m.es).

We invite applications for a 1-year full-time Research Assistant position (Pre-doc).
Candidates should have a strong interest in research in applied microeconomics. The work would relate to several research projects in the areas of Energy and Environmental Economics and Industrial Organization
carried out at EnergyEcoLab (https://energyecolab.uc3m.es/).

The position will be based at the Economics Department of UC3M, one of the leading economics departments in Europe. The campus is located in Getafe (Madrid, Spain).

Roles and responsibilities:
– Obtaining and preparing datasets
– Conducting statistical and econometric analysis
– Preparing literature reviews
– Assisting members of the research team in other aspects of the project

Desired qualifications and experience:
Bachelor’s or Master’s degree in economics, mathematics, statistics, or related fields. Candidates about to obtain one of these degrees are also eligible. Ideally, candidates should have the intention to work towards a PhD in one of the above disciplines.
– Excellent management and organizational skills. Meticulous, organized, and detail-oriented.
– Strong quantitative skills. Excellent knowledge of Stata or R. Knowledge of Python, web scraping, and text analysis would be an advantage.
– Flexible, self-motivating, independent, and able to manage multiple tasks efficiently.
– Proficient in English.
– Strong interests in academic research.
– Able to legally work in the European Union.

Job conditions:
– Full-time position.
– The job will be based at UC3M in Madrid/Getafe.
– Duration: 1-year: September 1st 2023 to September 1st 2024. With the possibility of being extended for a second year.
– Salary: 1500€/month, gross salary.

Candidates should apply via email to energyecolab@gmail.com before June 1, 2023. Candidates should submit a curriculum vitae; a short statement of purpose describing reasons for interest in this position and future career plans; contact details of two recommenders (recommendations will only be solicited for finalists); transcript from Bachelor’s or Master’s; and a writing sample (undergraduate or Master’s thesis) if available.
Interviews will be conducted remotely around June, 2023.