On 14 September 2022, Ursula von der Leyen, President of the European Commission, announced in her State of the Union speech a set of proposals to mitigate the impact of high energy prices. These are:
Joint gas storage: On average natural gas storage capacity across Europe stands at 84%, with the goal to reach maximum capacity in the coming months.
Hydrogen: €3bn funds to facilitate hydrogen development in order to switch from a niche market to a mass market product.
Energy savings: Member states are asked to reduce gas and electricity consumption by 10% with an additional 5% during peak hours.
Taxes on fossil fuel companies: The EU will apply additional taxes to fossil fuel suppliers given that the current crisis partly fuels higher profits from surging oil and gas prices.
Price cap on electricity: The EU proposes a €180/MWh day-ahead wholesale price cap for low-cost technologies. The scheme is expected to bring some €140bn in excess revenues that would be redistributed to the final energy consumers.
This article is about the price cap on electricity. Von der Leyen previously said: “Skyrocketing electricity prices are now exposing the limitations of our current electricity market design… We need a new market model for electricity that really functions and brings us back into balance.”
Which price cap to implement?
It is not clear what a new market design would look like, but many politicians have called for price caps, albeit in many different forms. Some have argued for a price cap on Russian gas, which is essentially a trade policy that would likely result in a full stop to gas deliveries by Russia to Europe. Others have called for a price cap on all the gas that Europe imports, but that would limit the ability to import liquefied natural gas (LNG) and threaten our energy security as a result. Yet others have called for a price cap on retail energy bills, like the ones that exist in the UK, which could be a game-changer for utilities and might trigger support schemes in order to keep delivering energy to households and businesses.
All these price caps, for good reason, did not make it to the final EC proposal. The proposal introduces a price cap on power generated by non-fossil fuels, in particular from solar panels, wind turbines, hydropower and nuclear power plants (NPPs) .
Capping the price of low-cost technologies
The proposal splits the merit order into two; one part for power-generating technologies with low marginal costs (wind, solar, nuclear power, hydropower and lignite power plants) and a part for technologies with high costs (plants that run on brown coal, oil and gas). Once the wind is blowing, the sun is shining, or a nuclear or hydro plant is running, it costs very little to produce an extra MWh of electricity. But coal and gas-fired power plants and oil aggregates need to buy expensive fuel.
The merit order ensures that the cheapest technologies enter the market first but implies that the price is set by the most expensive technology to meet power demand. In the current market, those are the gas-fired power plants, as gas prices have increased tenfold. What follows is an extremely high power price for all the technologies in the merit order. A price that meets a lot of resistance; why should technologies get a power price of hundreds of euros per megawatt-hour (MWh), while they were already profitable at power prices between 50-100/MWh?
The best way to solve this problem and bring down power prices is to reduce power demand to the extent that gas-fired power plants are no longer needed to meet demand. Unfortunately, this is not realistic in the short term as, on average, 23% of all the power in the European Union is generated by gas-fired power plants. And the shares vary considerably across Europe. It ranges from 42% to up to 65% in the Netherlands in the past 10 years, while it ranges from 2% to just 8% in France.
Given that European nuclear output volumes are expected to remain far below average for some more months and that hydropower reserves remain depressed, gas power plants are expected to continue to set the average market price.
Setting the cap at €180/MWh
A second-best solution is capping the power price for low-cost technologies (solar, wind, nuclear and hydropower). The EU proposes a €180/MWh day-ahead wholesale price cap for these technologies. The market still clears at the high power price set by the gas plants, but utilities need to pay back the difference between the market price and the price cap to a fund. If the market clears at €400/MWh, utilities have to pay back €220/MWh, which is called the inframarginal price. So in essence, this proposal is not a price cap for end-users, but a revenue cap for utilities with low marginal cost technologies (or inframarginal technologies) like wind, solar, hydro and NPPs.
The justification for this market intervention is that operators did not anticipate these revenues in their investment decisions and that they were profitable at power prices between €50-100/MWh. Governments also seek sources of funding to alleviate the burden of high energy prices for consumers. At a European level, this scheme is expected to generate up to €140bn that will be used to compensate households and businesses.
Note that Germany has proposed a technology-specific price cap instead of a general price cap of €180/MWh. It is still unclear if this will be adapted on a European level or if countries can choose their own method. The current EC proposal sets a maximum cap of €180/MWh, so technology-specific caps seem to be allowed if a revenue cap does not exceed €180/MWh.
In the long run, the price from the merit order needs to be high enough to cover the full costs of power-generating assets, not only the marginal costs. While the marginal costs cover the fuel costs, they don’t capture capital costs and operational costs.
The life-cycle cost of electricity (LCOE, or levelised cost of electricity) is a measure of the average total electricity costs of an asset over its full life cycle. The proposed cap of €180/MWh is sufficient to cover most solar and wind projects without subsidies and even for some projects with battery storage attached. But the cap does not cover the full and unsubsidised costs of new nuclear and hydro projects. These tend to be very capital intensive and have a history of large budget overruns. This could pose a problem for the ‘nuclear renaissance’ that French President Emmanuel Macron recently called for.
The proposed cap only covers a small portion of the large and complex power market
A single or one power market does not exist. In fact, power markets are multi-headed-beasts that consist of many segments which all serve a purpose to keep the physical complex power grids working. European power grids are among the most reliable grids in the world and power users, small to large, take it for granted that power is always available. In liberalised power markets this can only be done by a complex system of power markets, where vast amounts of power are traded within seconds and years in advance.
The proposed price cap only applies to the day-ahead market
The power market is in fact a collection of many complex sub-markets:
The proposed price cap only applies to the day-ahead market in which approximately 20-30% of the power is traded. So most of the power is not subject to the price cap. European power generators, for example, tend to pre-sell about 80% of their future power production in one-year ahead future contracts or through power purchase agreements (PPAs). Hence most of their revenues won’t be affected by the cap. Furthermore, supply is currently hedged at prices well below the cap (in the range of €30-85/MWh).
Utilities tend to pre-sell most of their power in future markets at prices lower than the cap.
The share of power generation sold upfront through exchanges or PPAs and the average power price:
Potential drawbacks: 10 things we will be looking out for
Market intervention is bound to run into drawbacks, especially in markets as vast and complex as power markets. The wholesale market cap in the Spanish power market provides a point in case. Due to power leakages and increased power generation from gas-fired power plants, gas use in the months following the introduction of the cap went up, not down.
These are the 10 things we will monitor closely in the run-up to, and after, the introduction of the proposed price cap.
1. Power leakage
A price cap in the day-ahead market might trigger generators of renewable assets to sell their power abroad, for example in non-EU markets like the UK and Norway. The power market in continental north-west Europe is well connected with these markets through the Britnet cable and North Sea Link. There were already plans for a EuroAfrica interconnector that will connect Greece and Cyprus with Africa in a couple of years’ time. And this energy crisis is likely to speed up investment in new interconnectors.
2. Power demand
The market reform aims to redistribute revenues from high power prices, but the scheme could trigger an increase in power demand. For example, bakeries are switching from gas-fired ovens to ovens that run on power. And in some countries, there is a run on electric heaters as households try to save on gas.
The size of this feedback loop is hard to anticipate, as it will depend on future gas and power prices. In any case, it remains to be seen to what extent the goal of lower power prices can be combined with the goal of power savings of 10% in overall demand and 5% in peak demand. Overall, savings tend to require high prices, while lower prices tend to increase demand.
3. Gas use in power sector
North-western European countries might need to generate more electricity with gas-fired power plants in case of sizable power increases and/or leakages. Hence gas use could go up instead, while this market design is intended to save gas and reduce the impact of high gas prices on the merit order.
4. Interference with longer-term power markets
Generators might shift from selling on the spot market (day-ahead market) to longer-term markets. For example, by selling power above the cap of €180/MWh for months ahead through in the futures market or through a PPA. Liquidity in the important day-ahead market needs to be monitored closely in order to keep this important part of the power market functioning.
5. Interference with shorter-term power markets (flex-market)
European power grids increasingly face congestion problems as the share of wind and solar power increases. Batteries can be a solution, both large-scale batteries and home-size batteries. The big question is to what extent the €180/MWh revenue cap in the day-ahead market is high enough to spur growth in battery capacity, for example by combining solar panels and wind turbines with batteries (so-called co-location business models).
6. Profitability of energy providers
In an earlier report published in June 2022, we concluded that a price cap can be a game-changer for European utilities and their profitability. As a result, utilities have been outspoken about their scepticism regarding price caps. Price caps are intended to minimise the windfall profits of utilities and to provide governments with a revenue source to compensate households and companies for high energy bills. But they should not reduce the profitability of utilities, as that will limit the much-needed and increasing amount of investments in the energy transition.
7. Implementation risk
The aim of this market intervention in the merit order of the day-ahead market is to provide short-term relief in European power markets. Will it be implemented quickly enough to provide relief this winter? History is not supportive as previous energy market reforms took years to be implemented. In that respect, a timeline of a couple of months seems ambitious but would mean that it is implemented at the end or after the winter period when energy prices are likely to be high. On the other hand, history also shows that policy interventions can be implemented quite fast in a crisis.
8. Regulatory risk
As more renewables enter the power system, gas and coal-fired power plants become increasingly important to act as a backup. In Europe’s predominant energy-only-market, generators with gas and coal-fired power plants are usually not paid to stand idle for the short term but at important moments that the system needs them. Hence the business case of investing in backup power is built on high and flexible prices, albeit for short periods. This form of policy intervention introduces a regulatory risk for the business case: a risk of governments intervening when prices are high. This might make investors wary to provide finance for much-needed backup capacity.
9. Legal risk
Will this policy intervention trigger lawsuits and hold up in court? It is not uncommon that major changes in market design are taken to court or that parties will call for ‘force majeure’ under existing contracts. This is not something we can assess as economists, but it is likely that market players will reassess their legal risk premiums in the business case for renewables.
10. Cost of capital and investor return
If regulatory and legal risks are deemed sizable, investors will require a higher return on their investment for low-carbon and/or fossil fuel power generation. This might have an impact on the high ambitions of governments to solidify, extend and transform European power systems and grids. This energy crisis calls for an even faster speed of the energy transition. Utilities and investors are needed to invest billions of euros. They will only do so as long as the risk-return profile is acceptable.
All in all, price caps sound appealing but in practice they are hard to implement and not without potential drawbacks. Since the State of the Union speech, we know the price cap is aimed at a specific segment of the power market, but many details have to be worked out. EU energy ministers will meet again on 30 September, so more details are expected in the coming weeks.
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