The debate is intensifying over how to decouple power prices from the extraordinarily high natural gas prices in Europe. Simona Benedettini and Carlo Stagnaro warn that the current problem of high prices is not caused by the mis-functioning of electricity markets, but by the exceptional trend in gas prices. So should the markets be re-designed at all? Will we lose the benefits of the current design, one being the reliable profits that renewables can make that incentivise further investment. The authors look at the proposals from the EC, Greece, Spain and Portugal, and Italy. They go into detail on the pros and cons, the price caps, market-splitting, the subsidy mechanisms and more. Any re-shaping of the market involves risks. It may also unintentionally increase the differences among member states and their relative competitive advantages and disadvantages. So it should be done with great caution, or perhaps not at all, say the authors.
Everybody wants to decouple power prices from natural gas prices in Europe – or so it seems. Most notably, European Commission president Ursula von der Leyen said in her 2022 State of the Union address: “The current electricity market design – based on merit order – 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”.
Decoupling gas and power is easier said than done. Several proposals have been put forward in the past few months. To mention just a few, Greece had long proposed a mechanism to split power exchanges between low- and high-marginal cost generators. On the other hand, Spain and Portugal have already adopted a mechanism with similar goals and which has been provisionally approved by the European Commission. Italy recently forcibly enrolled some renewable generators in a contract for differences scheme aimed at reaping these assets’ infra-marginal rents. The EU Commission itself put out a proposal for a Regulation which, among other things, aims to cap the revenues of infra-marginal electricity generating technologies. But what exactly do these proposals consist of? And what are the pro and cons?
Background: the ratio of system marginal pricing
The price of electricity is determined through a sequence of market sessions, which ensure the balance in real time between supply and demand. The so-called day-ahead market represents the main session. Exchanges on the day-ahead market aim at defining a production schedule for each generator to meet the demand in each hour of the following day.
To this end, a central counterparty collects and aggregates the bids submitted by electricity producers and consumers. Producers’ bids are ordered ascendingly according to their marginal costs of production, i.e. the fuel and CO2 costs: the resulting curve is known as the merit-order curve. Symmetrically, bids on the demand side are ordered descendingly according to the marginal utility of consumption. From such ordering a demand curve derives.
The point where demand and supply curves meet represents the equilibrium price. This price corresponds to the so-called marginal cost of the system, i.e. the marginal cost of production of the most expensive generating asset which is needed to meet the demand at any given point in time. Such technology is essential to fully meet the scheduled electricity demand of the day after. Such price is equally paid to each power plant. Consequently, while the marginal power plant receives a price which covers only the variable costs of production, the inframarginal power plants – i.e. those that are located to the left of the marginal power plant in the supply curve (see Figure 1 below) – will earn a price higher than their respective marginal costs and which allow them to also cover capital expenditures.
The ongoing debate at the EU level
The debate on the reform of the price formation mechanism and its adequacy with respect to energy systems dominated by renewable energy sources is not a new one. About a year ago, following the rise in gas prices during the last quarter of 2021, the European Commission required ACER, the agency for the cooperation of European energy regulators, to investigate the problem. Acer concluded that the system marginal price remains the most effective mechanism, as: 1) it allows to minimise the purchase costs of electricity; 2) provides adequate coverage of the investment costs of renewable electricity generation sources and nuclear power plants.
Despite the conclusions of ACER, the war between Russia and Ukraine, which led to new record levels in gas and electricity prices, has revitalised the debate about whether marginal pricing still fits for purpose. The recent proposals on the reform of the electricity market design have one characteristic in common that clearly distinguishes them from others advanced in the past (such as switching to a pay-as-bid rule): the new suggestions are based on the idea that despite electricity being a homogeneous product it may be both possible and desirable to split (physically, financially or administratively) the electricity market in two. One for power plants with high marginal costs and another one for low or zero marginal cost power plants.
Three main proposals stand out at the EU level
Three main proposals stand out at the EU level: 1) the adoption of a cap on the revenues of infra-marginal electricity generating technologies; 2) the creation of two separate power exchanges, one for low-marginal cost generating assets and one for high-marginal cost assets; 3) the payment of a subsidy to gas power plants for the purchase of the natural gas fuelling electricity generation (“el tope al gas”).
1) The adoption of a cap on the revenues of infra-marginal electricity generation technologies
This is the proposal made by the President of the European Commission in the context of the speech on the State of the Union of September 14th. The measure consists in setting a cap on the price that the infra-marginal power generating technologies can earn for each MWh sold. Electricity generation will continue to be sold at the market price and the equilibrium price will continue to be determined according to marginal pricing. However, if the equilibrium price exceeds the cap, inframarginal generators will have to claw back the difference between the market price and the cap. The financial resources so collected shall be used by Member States to finance interventions in support of household and business bills. The European Commission suggests setting such cap at €180/MWh. See Figure 2 below for a simplified representation of the mechanism
Italy, among the others, introduced a similar mechanism. The latter is applied to: 1) photovoltaic power plants with an installed capacity greater than 20 kW and which benefit from feed-in tariffs; 2) renewable power plants with an installed capacity greater than 20 kW and which, while not benefitting from incentives, entered into operation before 2010. The Italian mechanism has set a cap approximately equal to €60/MWh.
2) Market splitting
During the EU Council of Energy Ministers on July 26th, Greece made a proposal providing for the establishment of two distinct and consecutive sessions of exchanges on the day ahead market. A first session would involve only power plants whose cost structure is characterised by high fixed costs and low variable costs, i.e. infra-marginal generating technologies. A second session would instead entail programmable generating technologies characterised by positive marginal costs such as coal and gas power plants. In this second session, operators would bid for the electricity generation necessary to meet the residual demand, i.e. the share of consumption which is not satisfied by the production sold in the first session.
The profits for the power plants participating in the first session shall come from contracts for difference signed between electricity generators and public or private counterparties (such as final consumers, traders or aggregators). For power plants that are not able to find a counterpart in the market, so that a contract for difference could be signed, a voluntary participation in a newly set up market is envisaged. Such a market is called the green power pool and would be managed by a public entity operating as a single buyer. Power plants participating in the second session of the market would continue to value their production according to the System Marginal Price mechanism.
The equilibrium price for the electricity purchased and sold would be determined by the weighted average of three values: (1) the average price paid for the contracts for difference in the first trading session; (2) the clearing price of the second trading session; (3) the weighted average price, for the quantities traded on the green power pool. The mechanism appears complex and, in some respects, obscure. For example, it is not clear according to which rules the green power pool will be organised and operated.
The goal of the Greek proposal seems to structurally abandon marginal pricing (which is, in truth, the norm in commodity markets) to shift towards average pricing (i.e. a pricing mechanism based on average generation costs, including both variable and fixed costs).
3) El tope al gas
Spain and Portugal established a cap (“tope”) on the cost that gas power plants may pay for the purchase of natural gas needed for electricity generation. The cap is set at €40/MWh for the first six months of application of the measure. From the seventh month, the cap will be increased by €5/MWh every month until reaching the maximum value of €70/MWh.
If the market price of natural gas exceeds the cap, thermal generators are subsidised to cover the difference between the fuel cost and the cap. For example, if gas costs €100/MWh, thermoelectric producers will bid on the power exchange at a price consistent with the cap (i.e. as if gas costs only €40/MWh) and will be refunded the difference (€60/MWh). The corresponding subsidy is financed by different subjects: (i) buyers on wholesale markets in proportion to the volumes purchased; (ii) end customers who, having not chosen a supplier on the liberalised retail market, continue to buy electricity at regulated prices; (iii) the higher revenues due to the additional electricity exports to France caused by the reduction in the Spanish electricity prices due to the introduction of the tope.
By subsidising the cost of natural gas, marginal generators may bid a lower price in the day ahead market, driving down both the equilibrium price and infra-marginal rents.
These proposals all aim to lower the price of electricity. And, in a different way, they succeed. However, none of them are cost-free. Not only because in some cases, such as for the Iberian tope, it is a question of finding resources to finance an explicit subsidy or, as for the Greek proposal, it is necessary to resort to a public entity that buys electricity from those operators who have not been able to stipulate contracts for differences on the market. The most significant costs are, indeed, the collateral effects arising from interventions on the electricity market design.
Each proposal has pros and cons. The mechanism to cap the inframarginal rent has the advantage of not affecting equilibrium prices on the day ahead market. Therefore, this mechanism does not affect cross-border exchange of electricity between Member States. The Greek proposal has on its side the ambition to rethink the functioning of the market without attempting to patch up a mechanism considered obsolete. The Iberian mechanism fully safeguards the market design and intervenes upstream to address what is considered an exceptional phenomenon, that is, the rise in gas prices.
The last two mechanisms – the Greek and the Iberian ones – have an impact on wholesale prices and, therefore, they should be adopted at EU level in order to prevent distortions in cross-border electricity trades. In the case of the “tope al gas” as well as the cap on infra-marginal revenues, there is a further issue. If the cap is set “too low”, in the case of the tope the risk is to exacerbate the effects on exports and on the safety of the electricity system described above. In the case of the cap on infra-marginal revenues, the risk would also be to hamper the coverage of power plants’ investment costs.
The Greek proposal has further and specific limits. In the first place, there being no obligation to participate in the so-called green power pool, it is not clear how power plants that fail or do not find it convenient to sign contracts for differences on the market could be remunerated. Secondly, in the second session of exchanges (i.e. the exchange for high-marginal cost assets) there is a significant risk that the power plants may exercise market power if some of them find it essential to meet the electricity needs with respect to certain hours of the day and certain market zones. This possibility may prevent the goal of lowering the price of electricity. In addition, the complexity of implementing the mechanism should not be underestimated. A long time would be needed, indeed: 1) to adapt the rules for the functioning of markets and cross-border electricity exchanges; 2) to set up agreements between the power exchange operators and between them and TSOs to implement the new mechanism.
Finally, all measures – even if adopted at EU level – may unintentionally increase the differences among member states. For example, moving from marginal pricing to average pricing would obviously result in lower prices where the average costs of production are lower – i.e. where the incidence of natural gas in the national generation mix is lower. This may result in competitive advantages or disadvantages in downstream industries, particularly in the industries that are both energy-intensive and trade-exposed (such as steel, cement, paper, glass, etc.).
The idea of decoupling markets – through administrative interventions that separate renewable electricity generation sources from the others – has great political success but can take on many different meanings. Almost all, however, have to do with the desire to contain prices, reducing the amount of inframarginal rents. In the design of post-liberalisation markets, the marginal price system finds its justification in the need to encourage investment in new generation capacity, especially in plants – such as renewables – with high fixed costs but low or zero marginal costs. Direct or indirect caps on revenues may discourage new investments, to the detriment of both the efforts to get out of the current crisis by reducing dependence on gas, and the European decarbonisation programs. In any case, from this point of view the question is eminently empirical: a sufficiently high cap (for example the €180/MWh suggested by the European Commission) is not necessarily an obstacle in this respect, while a too low threshold (such as €60-70/MWh set in Italy) may be counterproductive. On the other hand, decoupling looks like an attempt to address a problem that does not stem from the mis-functioning of electricity markets: it derives from the exceptional trend in gas prices. One therefore wonders if this is not a case of following the ancient wisdom: if it ain’t broke don’t fix it.
Simona Benedettini is an independent consultant on energy policies and regulation
Carlo Stagnaro is the research and studies director of the Bruno Leoni Institute