The future is electric: LSEG’s vision for the European power transition

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 will impact both power supply and demand.

• The REPowerEU initiative promotes renewable deployment but also drives power demand, presenting challenges in meeting emission targets.
• Expectations for achieving emission reduction targets by 2030 are optimistic, particularly in the power sector, with renewable energy leading the way.
• Flexibility planning, demand-side management, and aligning renewable deployment with conventional power supply are crucial for a smooth transition.
  

The Power Research Team at LSEG has its origins in market analysis for short term market analytics 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 2035.

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 decarbonization goals. They also discuss the challenges we will face in the power sector in 2035 and unpack the corresponding need for action today.

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 extended the forecast period to 2035. To cover the full range of weather risk, we run the forecast under 30 different weather scenarios.

By now, we cover around 87% 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 power-related emissions.

FGM: For most countries – yes. Yet, while prices do decrease in summer, our model sees growing tightness in the winter months over time for some European countries. In Germany for example, this leads to a higher yearly average price in 2035 than we expect in 2025 – even though we expect the share of renewable power to exceed 80% in that year.

The reason for more 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  (by more than 10%) between now and 2035 in our modelled countries. While the flexible gas plant capacity is expected to grow, there will be a strong decommissioning of coal, lignite and nuclear plants. 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, especially in Germany.

FGM: Although we see capture rates decreasing for both solar and wind, capture prices remain high 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 looks at data for onshore and offshore wind production in the UK. Rather than earning the base price, wind assets tend to earn less because the more wind power is produced in the system, the lower the power price that they capture, i.e. the capture price. The difference is especially high in the winter months when wind is most abundant. Still, we can see that capture prices remain higher in the winter compared to summer months. The capture rates (capture price as share of base price) do not drop below 70% by 2035.

NG: We actually expect the power sector to achieve this target as early as next year! On one side, the energy crisis led to demand destruction, which accelerated the carbon reduction efforts. On the other side, it led to a strong push for renewable power buildout, of which we could see the fruits both last year and this year.

Even after accounting for demand growth through partial recovery of the pre-crisis demand and through the future electrification, the renewable electricity share will remain fairly high in the core economies and will allow for a significant drop in power sector emissions. We expect a 75% drop by 2030 and 80% by 2035.

The newly proposed 90% total emission reduction target for 2040 could be more challenging to achieve, because it probably requires a near -100% power sector emission reduction. For the 13 EU countries (+ Norway) covered, emissions drop continuously in our forecast, but we see that the emissions trajectory starts to flatten, 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. Abating the last 20% of emissions might take drastic and expensive measures, such as carbon capture, running gas plants on renewable hydrogen, and/or a quite radical flexibilisation of demand.

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 decarbonization 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! Whilst this would drive the decarbonization of the industry sector, of course it slows 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 until after 2035. We expect 8 mt of H2 production in the EU by 2035, and we further expect that renewable deployment will be achieved with a delay of 2-3 years.

NG: Our tight 2035 forecast reflects the uncertainties around flexibility in the future. 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 2035, 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 recognized and a capacity auction of at least 10GW for new hydrogen-ready CCGT plants is in the planning. We believe that this is enough on the supply side, but that there is significant potential in demand-side management that must be used:

What we see today is that for example EV charging peaks in the evening hours, which tend to be the most critical and expensive hours for the power sector. Yet, electricity tariffs usually don’t have hourly differentiation, or it is too weak to drive consumption shifts. 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 very tight, consumption is reduced to what is essential. 

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 incentivizing industrial plants to ramp down production for a pre-determined period in late January/early February, especially for industries which do not operate at full capacity all year long. This is especially relevant as heat pump consumption from heat pumps will add to the winter demand.

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.