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A combination of wind and solar power, otherwise known as Variable Renewable Energy (VRE), could make up the largest share of power capacity throughout Europe’s major markets – Great Britain, Germany, France, Italy and Spain – as early as 2023, according to new analysis from Wood Mackenzie.
By the end of the decade, the two technologies will have completely taken over the market due to strong government auction programmes pushing costs down as deployments ramp up.
The additional 169 GW of wind and 172 GW of solar power expected to be connected to the grid between now and 2040 will put unprecedented constraints on current system assets and market mechanisms. As such, flexibility will be vital to support this transition to renewable energy across Europe.
But what does a flexible power system look like in the long-term? Wood Mackenzie carried out modelling of Europe’s power systems using its hourly dispatch model and combined findings with forecast technology costs and economic models to create a new European energy storage long-term outlook.
“With conventional power plants in decline and non-dispatchable VRE taking over the system, the only dispatchable assets – those that can be used on demand – constructed will be purpose-built flexibility assets. These will be designed to compliment and capitalise on a new system architecture,” said Rory McCarthy, Wood Mackenzie Principal Analyst.
Pump storage will remain critical over the next two decades but new-build flexibility assets will be focused on interconnectors, gas peakers and energy storage. Combined deployments of the three technologies will grow from 122 GW in 2020 to 202 GW by 2030 and reach 260 GW by 2040. Without this new fleet, the system would become unmanageable.
By the 2030s, however, energy storage is expected to become the winning flexible asset due to plummeting technology costs and VRE’s dominance. Storage across all segments will grow from 3GW in 2020 to 26GW in 2030 to 89 GW by 2040.
Over the outlook period, system durations will increase in line with battery cost reductions. By 2040, 320 GWh of energy storage (excluding pump storage) capacity could be available to balance the system on a second-to-second basis.
Front of the meter storage will get the lion’s share of this capacity, however behind the meter demand will pick up through 2040 as hybrid renewable systems, electricity bill management and the resilience proposition become increasingly popular.
“Gas peakers are more essential than ever. They can ramp up to full output from warm in a couple of minutes for modern systems, have increasing efficiency levels at part loading and boast unlimited duration – assuming a reliable gas supply.
“Yet, by 2030, energy storage will beat gas peakers on cost across all our target markets, resulting in a cloudy outlook for any new future peaking turbines. Fuel and carbon prices are on the up, technology costs are not set for any major decreases and net-zero policies will eventually target the decarbonisation of all power market services. Unabated gas is likely to be the EU’s next target after coal, although market forces are already pushing it out.
“For storage and solar-plus-storage, technology costs will continue to decline. The levelized cost for a standalone 3-hour system will reduce by 33% through 2030. Its ability to take advantage of peaks alongside gas plants and capitalise on low and negative prices, which gas plants cannot, pushes it into preferred flexible asset territory,” added McCarthy.
Although energy storage will dominate the build out during the 2030s as gas peaker capacity plateaus, gas peakers will continue to be critical and will fulfil the role of backup and grid balancing. Gas units, including large CCGTs that cannot find a way to operate profitably with reduced utilisation and increased flexibility, will be forced to close.
“Energy storage and interconnectors, alongside demand response, will become the key tools when dealing with common low and negative net load hours. These periods occur when wind and solar generate more power than the system demands. Without these tools at the system operator’s disposal, we would have to curtail an eyewatering amount of clean energy and the grid would cease to provide high quality reliable power which could ultimately result in blackouts,” said McCarthy.
Coal is the biggest loser as a result of this VRE surge and environmental policy focus, with the power source only hanging on in Germany until 2038. Nuclear power will also lose out, dropping 41 GW by 2040 as an ageing fleet and new-build projects struggle with increasing costs, safety requirements and weakened government support across Europe. Large gas plants are also expected to experience a net reduction of 40 GW over this period as utilisation is pushed down.
So, how will the market finance and deliver this new flexibility fleet? “Policy makers have looked at the current system and developed a renewables and flexibility market around it. However, this market was designed for a very different generation of power system. Is now the time for a fundamental restructuring of the market?
“The market needs to provide the right signals for a high capex renewables buildout. Additionally, the system requires incentives and revenues for low carbon flexible solutions that provide value through service provision in addition to selling energy. This will become more apparent to policy makers as we fill the European power system with zero marginal cost, non-dispatchable power,” said McCarthy.