[Editor's note: This is the first in a series of articles on trends in European power generation companies' credit quality amid changes in power prices and contracting schemes.]

Electricity generation from wind and solar--negligible two decades ago--broke records in the EU last year. Combined, these renewable sources increased by 90 terawatt hours (TWh) to 721 TWh, more than the size of power demand in Belgium, Europe's 10th largest market. They represented 27% of the generation mix in 2023, up from 23%, enabling further cuts in greenhouse gas emissions, especially from coal. This was helped by a 3.4% drop in power demand following a 3.8% decline in 2022, according to the Agency for the Cooperation of Energy Regulators, to a 15-year low.

The ensuing excess power supply weighed heavily on prices, which halved over the winter. So, the increase in generation from renewables didn't translate into higher, more sustainable cash flows for European power producers. S&P Global Ratings anticipated that windfall profits from high power prices would not last, and they ended about 18 months earlier than expected (see "Europe's Utilities Face A Power Price Cliff From 2026," published June 22, 2023, on RatingsDirect).

Nevertheless, we expect rated European electricity producers can navigate through power prices of €60/MWh-€80/MWh that we forecast for 2024-2027. This is mainly due to the EU's Electricity Market Reform (approved by the European Council on May 21, 2024) and the related redesign of certain regulations and contracts last October. Power companies also have robust liquidity arrangements and hedging mechanisms, and systemically important participants may benefit from government backstops in the energy derivatives market. Yet we remain wary of margining requirements on hedging, having observed acute related financing needs in 2022-2023.

European Power Prices Experienced A Transformative Winter

Power demand and supply in Europe are both increasingly influenced by weather conditions. Consequently, given the inelasticity of demand, wholesale baseload power prices can be quite volatile, even on an intraday basis. Last winter was unusually warm. Therefore, during what should have been a period of peak power demand, electricity prices in spot and futures markets dropped to lows not seen since 2021.

The decline was also prompted by gas prices dropping to a low €24 per megawatt hour (/MWh) from the mid-€50 range before settling at €30/MWh-€35/MWh. What's more, we forecast wholesale power prices will continue to decrease and stay well below the 2022 peak, fluctuating mainly at €60/MWh-€80/MWh until 2027 before declining toward €50/MWh by the end of this decade (see chart 1).

Chart 1

Power prices could weaken slightly as we approach 2030, depending on the pace of electrification-led demand growth, such as from rollouts of heat pumps, data centers, and electric vehicles (EVs). This represents the main risk to our forecasts. Eurelectric, the Federation of the European Electricity Industry, anticipates power demand for EVs will increase 9x over 2023-2030 to 185 TWh.

A slower rollout of EVs, given their share of light-vehicle sales in the EU remains stuck in the low 20% range, and electric heat pumps (down 4% in 2023) may dampen power prices further. The impacts on power producers' credit profiles will likely be gradual. For example, because EVs contributed just 1.1% to overall power demand in Europe in 2023, current EV sales likely increase power demand by only about 30 basis points, equivalent to about 10 TWh.

Assuming EV power demand in the EU rises by the same amount each year, it could reach 100 TWh-160 TWh by 2030. This is almost as much as for data centers, and up from the 45 TWh-65 TWh estimated in 2022 (see "European Commission: Energy Consumption in Data Centres and Broadband Communication Networks in the EU," 2024). This implies growth of wind and solar generation of 80 TWh-100 TWh annually, versus 84 TWh in 2023. This volume can cover power demand from EVs and data centers multiple times and will therefore depress wholesale power prices.

Carbon Emission Prices Play A Key Role In Power Producers' Costs

The drop in the EU's carbon emission allowance (EUA) prices from €106 per ton in March 2023 to about €60-€70 in recent months has also weighed on power prices. S&P Global Commodity Insights anticipates EUA prices will stay at about €60 in the near term, despite shipping coming under the scope of the EU Emissions Trading System (ETS; see chart 2) by September 2025.

Chart 2

EUAs currently account for one-third of the marginal costs of gas-fired power generation, and even more for coal. We estimate that each €10 per ton EUA rise raises generation costs by almost €4/MWh of electricity for a 60%-efficient combined cycle gas-turbine plant (CCGT), and by easily double for coal. Thus, as renewables continued to push coal- and gas-fired capacity off the merit order in January to May 2024, coal-fired generation decreased 32% in Europe's five largest economies and gas-fired power by a lower but still material 22% or 5 gigawatts (GW).

In assessing the potential cash flows of high carbon-dioxide (CO2) emitters, we look at how the gross cost sensitivity to EUA prices is mitigated by EUA's correlation with power prices, depending on how much demand is covered by less-efficient fossil-fuel generation in the merit order. This strong correlation, alongside significant hedging, tends to protect near-term earnings from lower EUA prices, as illustrated by the resilient funds from operations (FFO) of key players. We observed, for example, that even with very high EUA prices in 2022-2023, the FFO of CEZ a.s. increased steadily and surpassed €3 billion over 2022-2024, despite the company buying €16 million-€17 million of EUAs annually. EPH (Energetický a Prumyslový Holding, then one of Europe's three largest CO2 emitters) also reported robust FFO over a similar period.

Yet, the longer-term business sustainability of fossil-fuel-fired power generation is fragile amid the energy transition. The correlation between power prices and EUA prices will weaken as fossil fuels' role as marginal price-setters reduces. We thus look at companies' medium-term plans to manage the energy transition and mitigate the associated risks.

Four Main Factors Support Power Utilities' Credit Resilience Versus The 2022 Price Shock

Power prices of €60/MWh-€80/MWh, although far below the €100/MWh seen in 2021, are not unusual and were the norm during the last decade. But an inflation-induced rise in capital expenditure (capex) and still-high interest rates continue to weigh on generation companies' free cash flow. This was less of a burden when power prices were stronger.

At the same time, European power utilities have been investing heavily in wind and solar, helping the region's capacity expand by a record 73 GW or 17% in 2023 alone, of which two-thirds (56 GW) came from solar. This pushed capacity to 219 GW for wind and 263 GW for solar. That year, power utilities made significant additional wind capex commitments (notably in U.K. offshore) and permissions for wind power projects in Germany and Spain surged; coal-fired generation also halved in just seven years. Now, persistent sector-specific inflation (apart from solar panels) is pushing up capex on wind and battery projects. We believe the resulting pressure on cash flow will somewhat constrain utilities' creditworthiness in the medium to long term.

Yet, in our view, Europe's power producers are better prepared for price shocks than during the last decade, mainly due to:

• The stabilization of Europe's gas supplies after Russia's abrupt curtailment at midyear 2022.
• The EU power market reform, proposed in October 2023 and adopted on May 21 this year, which helps maintain significantly lower gas and power prices than in 2022, implying that--combined with stable gas supply--price swings should be milder in future.
• Utility companies' more robust liquidity arrangements and the introduction of government backstops for systemically important participants in the energy derivatives market.
• Active hedging at the higher 2022-2023 prices, which should help most power generation and integrated utilities consolidate their financial profiles over 2024-2025 (see table).

As a result, overall, we do not see significant near-term risks to our ratings on European electricity utilities from power prices. That said, these companies' ability to cope with sudden changes in power prices will be influenced by how they balance investments in the energy transition against debt repayment and shareholder returns.

From 2027, Renewables Growth Could Erode Power Prices If It Outpaces Electrification

On average, the share of renewable energy sources in the EU's supply mix reached a record 44% in 2023 (47% in the U.K.) up from 37% in 2022. While impressive, this increase also stemmed from lower demand and is still some distance from the about 70% contribution to meet the REPowerEU target of 42.5% renewables in the total energy mix by 2030.

Progress in renewables is good news for the energy transition, but not necessarily for power prices and power producers' credit quality. We expect power prices to decline as growth in demand for electricity continues to lag the net increase in supply, with gas prices remaining a key driver. More specifically, for northwestern Europe and in real 2024 terms, we believe that:

• In 2024-2027, power prices will be roughly within the €60/MWh-€80/MWh range, at a slight premium in real terms compared with 2018-2019 levels. This is based on our expectation of sluggish demand recovery and our assumptions for CO2 and gas prices (see "S&P Global Ratings Makes Modest Change To AECO Natural Gas Price Assumption; Other Prices Unchanged," published June 11, 2024, on RatingsDirect). Power demand, flat in the first quarter of 2024 year on year, might recover to 2019 levels only in 2026.
• From 2028, faster deployment of low-marginal-cost renewables (net of coal, gas, and nuclear phase-outs) than growth of electrification-led demand could push prices down to €50/MWh-€60/MWh.

Notably, for Europe's top five markets, power demand, flat in the first five months of 2024 year on year, might recover to the 2019 levels only in 2026. We have revised our power demand growth projections for 2024-2030 upward by about one-fifth, particularly for the U.K. and France, versus downward for Spain (-2%). This supports our price expectations in these countries. We now expect steady 3.6% annual demand growth on average, with strong variations by country (see chart 3), unless it falters again, as in 2024, when we forecast it will barely exceed 1.0%.

Chart 3

A look at individual countries' power mixes reveals more details (see charts 4 and 5):

• Wind power will increasingly supply markets in Northern Europe, resulting in either transmission lines becoming more congested (such as North to South in the U.K., Germany, Sweden, and Norway) or prices trending downward where price-bidding zones are narrow, such as in Northern Sweden or Norway.
• A similar situation will affect solar power in Iberia (Portugal and Spain), Southern Germany, and the Netherlands.
• Demand patterns will depend partly on how quickly heat pumps and EVs are deployed, which tends to vary by country. They will also be influenced by the pace of industry electrification, with robust demand from data centers and heavy industry in Germany, Belgium, and the Netherlands, and new energy-intensive plants in the Nordics. Overall, power demand is rising more steeply in the north of the continent.

Chart 4

Chart 5

Phasing Out Coal And Unabated Gas-Fired Power Is Just A Matter Of Time

In the EU, the decarbonization of power generation is advancing, led by wind and solar. In 2023, these two sources raised their contribution to total generation to 27% from less than 5% in 2009. According to the latest European Electricity Review (Ember, 2024), the power sector reduced emissions by a massive 19%--by more than 150 million tons--compared with the figure in 2022 (see chart 6). Power generation now accounts for less than one-quarter of CO2 emissions across sectors, whereas non-energy sectors reduced emissions from fossil fuels by only about 4% in 2023.

Chart 6

Consequently, we estimate that, in 2023, the carbon intensity of the EU's power grid reached a record low of about 210 grams of CO2 equivalent per KWh from 251 grams in 2022. According to the European Environment Agency, carbon intensity could drop to only about 110 grams by 2030. That would be consistent with virtually eliminating coal- and oil-fired electricity, per the European Network of Transmission System Operators' 10-year development plan report, published jointly for power and gas in May 2024.

Yet, given the power industry's remaining reliance on fossil fuels, the rising price of carbon emission allowances could become a material factor for power producers relying on fossil fuels. We see that about 333 TWh of coal- and lignite-based power generation--enough to more than supply the whole of Italy--has been removed from the grid (see chart 7). Effectively, such power sources are gradually becoming uneconomical due to higher CO2 prices and renewables that offer lower variable-cost generation, pushing them out of the merit order on the short-term power market.

Chart 7

We estimate that, by 2033, Europe will have eliminated nearly all coal- and lignite-based electricity production, apart from Poland and 5 GW of lignite capacity in Eastern Germany. This will profoundly reshape its power markets in terms of price drivers, levels, and volatility. Challenges to grid stability will therefore become even more acute.

Related Research

• Europe's Utilities Face A Power Price Cliff From 2026, June 22, 2023
• S&P Global Ratings Has Lowered Its North American And European Gas Price Assumptions For 2024 And 2025, Feb. 20, 2024

External Research

• European Commission: Energy Consumption in Data Centres and Broadband Communication Networks in the EU, 2024
• European Electricity Review, Ember, 2024