The Power Research Team at Refinitiv unpacks the complex and dynamic European power transition.
- The electrification of heating and mobility is progressing at full speed, strengthening the role of power within the total energy mix.
- Despite this, in most European countries, our model predicts a higher yearly average price in 2030 than we expect in 2024.
- In our base case, we also take a cautious approach and assume that the REPowerEU target will not be met as early as 2030.
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The power sector lies at the core of energy transition: the electrification of heating and mobility is progressing at full speed, strengthening the role of power within the total energy mix. At the same time, we are operating in the advent of the clean hydrogen era, which impacts both power supply and demand.
The Power Research Team at Refinitiv has its origins in market analysis for analytics in the short term and for a two to three year horizon for power hedging and trading. More recently, following increased interest in understanding the long term evolution of the power sector, our power analysts have worked on an extension of their market model to 2030.
In this Q&A, Francisco Gaspar Machado (FGM) and Nathalie Gerl (NG) tell us more about how the European power system is simulated, the assumptions that underlie their model and where they see the achievement of decarbonisation goals by 2030. They also discuss the challenges we will face in the power sector in 2030 and unpack the corresponding need for action today.
Q1: What is your approach to simulating the European power sector?
NG: Coming from a trading analytics environment, we already had powerful and highly detailed models set up for price forecasting with hourly granularity. Our forward model computes the spot (day ahead) outcome for the next two to three years to predict the fundamental value of the respective forward contracts.
For our long term view, we extend the forecast period to 2030 – and we aim to launch an extension to 2035 shortly. To cover the full range of weather risk, we run the forecast under 30 different weather scenarios.
Geographically, we cover around 85% of the EU power sector – in addition to Britain, Norway and Switzerland. This allows us to approximate developments in Europe/ the EU as a whole and to simulate EU-ETS power-related emissions.
Q2: What price view do you have for the end of the decade – will power prices decrease with the continued addition of low-cost renewable electricity generation?
FGM: Actually, no! While prices do decrease in summer, our model sees growing tightness in the winter months throughout the decade. In most European countries, this leads to a higher yearly average price in 2030 than we expect in 2024.
The reason for this tightness is that high (and increasing) demand in winter will still require thermal generation in most hours – and to a greater extent than today – when renewable and short-term storage (batteries) output are low. At the same time, the thermal stack is set to decrease substantially (by approximately 9%) between now and 2030 in the modelled countries. This is driven by the decommissioning of coal, lignite and nuclear plants not being replaced by enough new capacity. This in turn means that there will be hours in which high-priced emergency supply or even demand shedding will set prices at very high levels.
The exception to this trend is Iberia, where prices in the winter remain low owing to high levels of renewables, a comfortable gas capacity providing flexibility, as well as substantial nuclear capacity that providing a stable baseload supply.
Q3: What does this mean for renewables? This surely results in very low capture rates. Is there still willingness to invest?
FGM: Although we see capture rates decreasing for both solar and wind, capture prices remain at similar levels for wind in most countries owing to high power prices in winter, when wind output is also highest.
We still see a lot of willingness to invest, as renewables developers have been successful in securing revenue through Power Purchase Agreements (PPAs). In terms of these agreements, buyers purchase power from renewable assets, decreasing their carbon footprints and directly supporting energy transition by affording asset owners more certainty in their revenue streams. This is often essential for financing renewable assets. Our long-term price model can help both parties settle on a price and the structure of the PPA by providing the expected and at-risk revenues under different weather scenarios.
As an example, let’s look at data from an onshore UK windfarm in the following diagram. Expected (and P90) capture revenues are higher than pay-as-produced PPA until 2026, even at a relatively high PPA price of 100 EUR/MWh. Baseload PPAs deliver lower expected revenues, even at a 25% price premium.
Q4: The recent reform of the EU-ETS carbon trading scheme has significantly increased the target for 2030 emission reduction to 62% vs. 2005 levels. In your view, can this target be achieved by 2030?
NG: We actually expect the power sector to achieve this target as early as 2028! Even after accounting for demand growth through growing electrification, the renewable electricity share will be fairly high in the core economies and will allow for a significant drop in power sector emissions.
For the 13 EU countries (+ Norway) covered, emissions drop continuously, even though by end of the decade we see that the emissions trajectory starts to flatten a bit, meaning that there is a certain amount of fossil-fuelled power that can only slowly be abated. This is because, across all weather scenarios, there are hours where weak wind speeds and/or solar radiation will drive high demand for dispatchable power – even where hundreds of gigawatts of installed renewable energy capacity exists.
Q5: How does the REPowerEU plan from the EU impact your view?
NG: The REPowerEU initiative consists of two pillars that have opposing effects on the future power balance:
On one hand, the intention is to promote renewable deployment, especially of solar power. This will contribute to faster decarbonisation and, especially in summer, result in a healthy supply of zero-cost power during most hours.
On the other hand, REPowerEU also drives power demand. Apart from calling for a faster rollout of heat pumps, the plan also contains a highly ambitious goal for green hydrogen: it cannot be ignored that a large part of the planned renewable electricity additions will be dedicated to green H2 production and will therefore not be available for meeting power grid demand. We estimate that the 10mt of renewable H2 envisaged by the plan will require approximately 500TWh of electricity input – comparable to the 2030 power consumption of France! While this would drive the decarbonisation of the industry sector, it could slow down the emission target achievement of the power sector itself.
We simulated the impact of full REPowerEU target achievement – both renewable capacity deployment and 10mt H2 production by 2030. This additional renewable capacity would indeed be sufficient to meet the hydrogen-driven demand growth and most countries would still meet their emission reduction targets.
In our base case, we take a cautious approach and assume that the REPowerEU target will not be met as early as 2030. We expect 4mt of H2, rather than the planned 10mt, and we further expect that renewable deployment will undershoot as well. Our assumptions are closer to the “Fit for 55” scenario published by the European Commission in 2022.
Q6: Policy focus seems to be on heavy deployment of renewable electricity. What else do you think can be done now to ensure a smooth transition of the power sector?
NG: Our tight 2030 forecast reflects the uncertainties around flexible and dispatchable supply at the end of the decade. Flexibility planning needs to happen in conjunction with the planning of renewable deployment and conventional power decommissioning, but we see a misalignment here, especially in the case of Germany. In 2030, the conventional power supply will look completely different to how it looks in 2020! With zero nuclear power and the halving of the coal stack, the potential for supply squeezes on cold and wind-poor winter days will be much higher. This risk has been recognised and a capacity auction of at least 15GW for new hydrogen-ready CCGT plants is in the planning. We have some doubts over whether that capacity will be ready and installed in time and, moreover, if 15GW is sufficient in the first place. In our modelling we see that there can, at times, be supply gaps of over 25GW in single hours.
We also believe that there is significant potential in demand-side management. When the power system becomes tight, the situation often lasts for just a few hours. We need to become more creative in shifting demand, both in the residential and the industrial/commercial sectors. Price signals from smart meters could be strengthened, so that when supply is tight, consumption is reduced to that which is absolutely necessary. Our forecast shows that the month of January has by far the strongest price spike potential within the year. There could, for example, be a case for incentivising industrial plants to take holidays for a pre-determined period in late January/early February. We need to think outside the box and question if a 24/7 right to use electricity at will is compatible with the reality of the future: non-constant power availability.
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These key insights from our team deliver a concise snapshot of some of the core challenges and opportunities that will define the power sector over the remainder of the decade – and our analysts will continue to deliver the data, tools and insights that stakeholders will need as they navigate the dynamic landscape of ongoing power transition in Europe.
