According to International Energy Agency (IEA) website publication on Renewables 2022 Analysis and forecast to 2027 report, in the European Union, policy schemes make more than half of utility- and commercial-scale renewable power capacity (including large-scale hydropower) eligible to receive wholesale energy prices. Excluding hydropower, wholesale market exposure is under 40% for wind, solar PV and bioenergy technologies.
Hydropower plants, which account for one-quarter of EU installed capacity (built mostly during the 1960s and ‘70s), are usually not covered under any policy scheme unless they are small-scale projects. Thus, a significant majority of these largely amortised hydropower plants could receive high wholesale electricity prices in the absence of long-term fixed-price bilateral contracts. For instance, a recent financial report of the Norwegian utility Statkraft, which has one of the largest operating hydropower plants in Europe, indicates that only one-third of its generation is hedged in the medium and long term.
Over the last decade, European renewable power incentive schemes have evolved from FITs to competitive auction schemes with FIPs, exposing renewable technologies (especially utility-scale wind and solar PV plants) to market prices. The classical feed-in-tariff policy commonly implemented in most EU member countries until 2015-2017 for utility-scale and commercial projects is based on 20-year fixed-price contracts, and thus does not expose renewable power plants to market prices. We estimate that the significant majority of onshore wind, solar PV and bioenergy projects (totalling around 200 GW commissioned between 2003 and 2013/14) are under classical feed-in-tariff schemes, with the remainder contracted mostly under former green-certificate arrangements exposed to wholesale price revenues.
Since 2012/13, EU countries (led by Germany) have been introducing sliding FIPs with a floor price defined through competitive auctions. The purpose of these schemes is to facilitate market integration of renewables by enabling developers to sell electricity in the spot market while receiving subsidies to top up their revenues. However, contract prices awarded in feed-in-premium schemes were lower than average wholesale prices over the past decade, enabling projects to receive subsidies. Today, these projects (onshore wind, offshore wind and utility scale solar PV), located mostly in Germany, the Netherlands and Denmark, could benefit from high spot-market prices. In Spain, the RECORE regime, which caps the returns of most wind and PV plants commissioned before 2019, also enables developers to receive market revenues if projects have already achieved regulated profits.
Recently, more EU countries have introduced CfD auctions. CfDs require developers to pay back additional revenues if wholesale prices exceed the strike price. They provide revenue certainty and enable developers to share risks with off-takers, minimising the impact of wholesale electricity prices on project economics. In the European Union, the majority of onshore and offshore wind capacity operational today could receive market prices through FIPs, while utility scale solar PV projects are mostly exposed to either classic FITs or CfDs. For commercial solar PV projects, FITs or fixed tariffs for remuneration of excess generation remain the common incentive schemes. Thus, almost 70% of these projects cannot receive wholesale electricity prices.
