European Power Markets

The European power markets have entered an unprecedented period of transformation. Power costs have reached new highs: in many European nations, baseload week-ahead rates have surged above €200 per megawatt-hour, roughly four times the average historical level. A jump in natural-gas and carbon prices, which now approach €100 per MWh2 and €60 per metric tonne, respectively, have caused the increase. This has impacted the cost of electricity generated by natural-gas power plants, which sets prices in European markets.

At the same time, due to the uncertain output of renewable assets and a tight supply and demand balance in the European power grid, price volatility is reaching new highs. For utilities, dealers, and large power consumers, navigating this new standard will be a significant challenge, emphasizing the significance of building robust power-asset portfolios and controlling risk.

Sustained Growth in Power Demand

Electricity demand is expected to increase steadily in Europe; the main factors behind the surge will be the electrification of transport and a ramp-up in the production of green hydrogen through electrolysis, requiring renewable power.

As a result of the electrification infrastructure development and national emissions standards, transportation power consumption will grow at a CAGR of 14 %. Green-hydrogen production’s power requirements will grow at a CAGR of 40 %, nearly a third of Germany’s total consumption. Because efficiency measures will primarily offset the electrification of industrial processes and domestic equipment, demand in the industrial, commercial and residential sectors will only expand marginally.

A Future Energy System Dominated By Irregular Production, With Uncertainty about Total Capacity Rollout

Between 2021 and 2030, more than 650 gigawatts of intermittent renewable energy, such as wind and solar, are expected to be created. In 2030, sporadic renewables will account for roughly 60% of total installed capacity in Europe, up from about 35% in 2021. However, it is unclear whether the current rate of renewable energy deployment will be sufficient:

In many European countries, project approvals have been delayed. As a result, the delay between project proposal and commissioning can be as long as seven years. The grid’s upgrading faces considerable hurdles as renewable energy production causes nodal imbalances, necessitating utilities’ new transmission and distribution assets.

In a growing number of countries, restrictions on the growth of renewable assets have been imposed, such as onshore wind development, due to concerns about biodiversity or noise and visual pollution.

The Phaseout of Coal and Nuclear Assets

Because coal is being phased out and nuclear facilities are dismantled, a significant decline in dispatchable or controllable power assets is expected. The dependency of the electricity system on weather-dependent renewables and natural gas is highlighted in this issue. Power shortages could result from poor wind and sun conditions and a slower rate of renewables development. Given the demand sensitivity of heating and the necessity for dispatchable power generation, gas prices may fluctuate considerably. Between 2021 and 2030, European coal and lignite capacity will shrink by almost 70%. Western and Northern European countries are leading these cuts.

Many EU countries are not renewing their nuclear-power assets and are making little new investments. Between 2021 and 2023, nuclear capacity is expected to fall by 23%. Germany, Belgium, and Spain have announced that their nuclear power stations will be shut down by 2022 and 2030, respectively. France has begun the process of decommissioning its oldest nuclear reactor to construct a 1,650-MW new-generation reactor. The United Kingdom is working on a new 3,200-MW nuclear project, yet delays and prices may restrain the country’s nuclear progress.

The Critical Role of Gas and Batteries to Bridge Dispatchable-Power Capacity Needs

The power sector must compensate for the loss of dispatchable assets to maintain grid stability. As coal and nuclear output dwindle, all expect new ones, such as natural-gas power plants and batteries, to help balance the system. More than 15 GW of natural gas is planned to be installed, predominantly between 2021 and 2030, while more than 82 GW of battery storage is expected to be installed. However, many investments rely on national capacity procedures to avoid stranded asset risks for investors. Compatibility with EU rules and the EU’s Fit for 55 packages will also factor in capacity mechanisms. Natural gas is likely to be a significant source of dispatchable power in general, particularly during periods of low renewables generation.

Declining battery storage costs may stimulate the deployment of batteries to address the dispatchable capacity shortage. However, because European countries have not jumped-started the industry with storage laws like some US states, the pace may be slower than expected. Still, there are reservations about the cost-cutting potential. The recent escalation in the cost of battery materials and worries about the speed of the rollout of “giga-factories” for grid-scale batteries are among the uncertainties.

Implications for the European Power System

Fundamental changes in the European power system are expected to result in a considerably more unpredictable power-pricing environment, as evidenced by this year’s increase in power prices. With daily and hourly prices reaching new highs, Europe is approaching a period of extraordinary volatility. In Germany, the EU Power Model, upwards of 3,000 hours a year might be priced at more than €100 or less than €10 by 2030, compared to just a few hundred hours today. This volatility may prompt market participants to adopt new strategies, such as raising their bids for electrical supplies or hedging their future demands.

The merit-order cost curve, which depicts the power market’s price-setting mechanism, is one approach for stakeholders to better comprehend the power market’s dynamics, including volatility. Five factors are essential in predicting future changes in electricity costs and price volatility:

The marginal production costs of thermal power plants are changing due to gas, coal, and CO2 pricing changes. The market’s clearing price volatility is driven by the rise or decrease of gas, coal, and CO2 prices.

Renewable energy’s inconstancy. The amount of renewable energy produced will push the curve to the left or right, perhaps resulting in either low or highly high clearing prices.

New builds with dispatchable assets. Uncertainty over the volume and cost of new dispatchable assets (such as batteries and combined-cycle gas turbines) could cause clearing prices to rise or fall.

Uncertainty in average load Hourly power demand volatility from sources such as electric vehicle charging and industrial electrification could lead to supply shortages and high clearing prices at particular times.

During shortages, strategic offers are made. Expected supply shortages could encourage market actors to bid their capacity at prices higher than the marginal cost, theoretically up to the maximum permissible price, in a growing number of hours.

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