Russia’s invasion of Ukraine triggered a global energy crisis, leading to sharp increases in oil, natural gas and coal prices. As a result, electricity prices in Europe have risen drastically because natural gas-fuelled plants remain the price-setter in the wholesale market. Furthermore, high fossil fuel prices have resulted in windfall profits for some energy companies. In fact, the profits of major oil, gas, coal and refinery companies in the first half of 2022 more than doubled from the same period last year, and discussion on windfall profits in the European Union has extended to electricity generators (including renewables-based ones) that can produce electricity at lower marginal costs than natural gas-fuelled power plants.
In October 2022, the European Council passed a regulation on an emergency intervention to address high energy prices. The regulation proposes windfall-profit levies on fossil fuel producers through a temporary solidarity contribution, and on electricity generators (or inframarginal electricity producers) that have lower marginal costs than the price-setting gas units.
The Council also introduced plans to cap the wholesale electricity price at EUR 180/MWh or lower, and expects that member countries would raise EUR 117 billion annually. This market intervention aims to reduce electricity prices to protect and support vulnerable energy consumers. As the proposal’s interpretation and implementation by each member state remains an uncertainty, its implications at the country and EU level are difficult to estimate. In addition, several European countries have already introduced national-level windfall taxes for electricity generation and trading companies.
The direct answer to whether renewable power plant owners are making windfall profits is highly complex. While renewable energy policies can provide insights on whether developers are allowed to receive higher revenues from the market, they can only partially answer the question on windfall profits because data are limited concerning non-policy factors, including long-term bilateral power purchase contracts, developers’ hedging strategies and exposure in the wholesale electricity market. To understand these non-policy factors, we examined the balance sheets of the European utilities with large operational renewable and fossil fuel capacities.
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.
Financial situation of selected large European utilities
The financial statements of large European utilities indicate higher revenues resulting from steep fossil fuel and electricity prices in the first half of 2022 compared with the same period in 2021. However, unlike for oil and gas majors, higher revenues for European utilities have not always translated into profits in recent months because utility companies have diverse business profiles, allowing them to compensate losses in one business segment with profits from another. Plus, technological and geographical portfolios as well as business strategies have been important determinants for how companies are navigating the global energy crisis.
Our analysis cannot be generalised to cover the entire EU market, as it assesses just ten large utilities, or around one-quarter of total installed EU electricity generation capacity. The majority of installed renewable capacity is owned and operated by private companies that are not obligated to disclose their financial standing.
All the major utilities reported significantly higher revenues but also higher costs in H1 2022 than in H1 2021, with hikes ranging from 30% to 170%. Higher average electricity and gas prices since November 2021 have clearly boosted revenues. However, even though all large utilities reported higher revenues in H1 2022, their financial performance and profitability within Europe were quite different due to a myriad of variables, including generation mix diversity; the splitting of earnings before interest, taxes, depreciation and amortisation (EBITDA) into different operations involving regulated networks, contracted renewables and trading activities; and exposure to retail business.
An increase in costly fossil fuel-based generation is compensating for lower hydropower output in Europe. Indeed, extreme drought conditions in Italy, France, Spain and Portugal reduced EU hydropower output by more than 15% in the first half of 2022. Lower hydropower generation reduced the European EBIDTA of Enel, Iberdrola and EDP, although higher profits from increased fossil fuel-fired generation and trading activities made up for this loss. In addition, these utilities had to purchase energy from the market at higher prices to meet their retail customer obligations, putting further pressure on their profitability.
EDF’s nuclear power generation dropped more than 15% and hydropower production was 23% lower in the first half of 2022 compared with the same period in 2021, requiring the company to purchase electricity from the spot market at high prices and reducing its revenues significantly. In some cases, higher wind and solar PV generation and additional installed capacity have contributed to profitability. For example, EnBW registered an EBITDA rise of 43% related to its renewable energy business, and Orsted, a utility with major investments in renewable generation, increased its EBITDA (excluding new partnerships) by 48% relative to H1 2021.
Exposure to retail and customer business reduced utilities’ profitability. Most major European utilities have large retail customer businesses. While electricity generation and purchase costs have risen drastically, retail price increases remain limited in most parts of Europe due to regulated-price contracts and to additional government interventions to protect consumers in the current extraordinary situation.
For instance, Spain and Portugal capped the wholesale gas price for power plant use at EUR 40/MWh, leading to relatively lower wholesale electricity prices and shielding Iberian electricity consumers. In general, most utilities’ retail businesses recorded a lower EBIDTA in the first half of 2022 than in 2021. For instance, EDF’s EBITDA dropped sharply in France due to the government’s regulatory measures to limit sales price increases for consumers in 2022.
Hedging strategies and long-term contracts are key tools for utilities to navigate the current European energy crisis. The exposure of European utilities on wholesale markets can vary significantly, impacting their profits. For instance, only one-third of Statkraft’s total generation is hedged through 2030, resulting in higher revenues from the electricity spot market. At the same time, however, Orsted’s low 10% exposure to the wholesale market limits the company’s ability to profit from high market prices. For Verbund, the company’s hedging strategy has increased its profits, as it was able to obtain an average sale price of EUR 112.5/MWh in H1 2022, boosting its electricity revenue considerably and raising its EBITDA, 111% from the previous year.
Meanwhile, Spain introduced a clawback mechanism for forward electricity contracts of more than EUR 67/MWh, but Iberdrola contracted unregulated renewable generation with its retail business at EUR 66/MWh in January 2022, before Spain had introduced the clawback mechanism. The fixed-price policy partly sheltered the company from volatile wholesale market prices.
Policies and regulations on windfall profits
Several European countries have introduced regulatory measures to tax energy companies’ extraordinary profits or revenues, with the aim of limiting inflation increases and protecting society’s most vulnerable consumers. For the electricity sector, governments expect to collect additional taxation income on the profits or revenues of generation units that have low marginal costs, including renewable energy producers and energy trading companies that have been selling/trading generation in the wholesale market.
Five European countries (Greece, Hungary, Italy, Spain, and Romania) already began implementing new taxation and fiscal measures in 2022 to claw back windfall profits covering periods of six months to three years, while discussion on this topic is ongoing in nine other EU countries. In addition, Germany has announced that it expects to raise about EUR 10 billion by imposing windfall taxes on electricity generators, and Belgium anticipates EUR 3 billion. While remuneration policies may enable renewable energy generators to tap into the wholesale market to receive higher revenues, hedging mechanisms and long-term bilateral contracts make the actual amount governments could eventually collect less certain.
Implications for the energy transition in Europe
Accelerating renewable energy expansion is crucial to reduce EU reliance on imported fossil fuels from Russia. Large utilities and independent power producers continue to be the main investors in renewables in Europe and thus have a pivotal role in increasing the pace of wind and solar PV expansion. Following the European Council’s October 2022 regulation of price caps for electricity generators, more EU countries are expected to introduce new regulatory measures.
The current regulation enables member countries to define their own price caps as well as clawback mechanisms for profits or revenues, depending on national circumstances. However, inconsistencies among regulatory regimes could create uncertainty for investors, especially if they make the business case for renewables less appealing. Thus, it is important for regulations to tax profits from energy sales in the wholesale market and not revenues.