European electric utilities are enjoying a good moment. After a turbulent 2022, wholesale baseload electricity prices have settled at historically high levels, of about (and often above) €100 per megawatt hour (MWh), across the region's five biggest markets (Germany, France, Italy, Spain, and the U.K.). Utilities with exposure to merchant power generation have benefited from resultant strong earnings and improved liquidity.

But the clock is ticking. S&P Global Ratings expects current prices will persist out to the end of 2025--a view that aligns with forecasts produced by S&P Global Commodity Insights, a division of S&P Global, as is S&P Global Ratings. That view is supported by a combination of elevated natural gas prices, the phasing out of coal generation, the shuttering of nuclear plants (notably in Spain and the UK), and France's struggles to increase its nuclear sector output, which was at a record low in 2022.

Then, from 2026, prices are likely to fall, and rapidly.

The catalyst for that change will be an acceleration in new, intermittent capacity, led by double digit annual growth in wind and solar capacity. The resulting surge in renewable output will likely outpace electricity demand, expected to grow annually in the single digits, and will dilute the influence of high-cost natural gas on electricity prices, removing a key driver of the recent elevated baseload prices.

The shift promises to be drastic. We expect wholesale baseload prices will dip increasingly often into single digits by about 2030. Electricity utilities' ability to cope with that change will be dictated to a great degree by decisions made now and which balance investment in the energy transition, debt repayment, and shareholder returns.

Baseload Prices Are At Historical Highs

To understand why electricity prices are poised to fall, it is necessary to understand what is sustaining them. As a starting point it should be noted that baseload prices have already fallen about 50%, across Italy, Spain, France, the U.K. and Germany (collectively the E5), from their peak during the turmoil of 2022 (see chart 1).

Chart 1

Despite that decline, power prices at over €100/MWh, remain historically high and are producing significant cash flows for merchant power generators and for those that cushioned the decline with hedges at higher prices (see table 1 for some examples).

Table 1

A handful of factors are responsible for the continued strong prices. They include:

High natural gas prices that continue to be driven by liquified natural gas (LNG) import prices.   Plants fired by fossil fuels, of which gas is the most important, still account for 30%-40% of baseload electricity in markets including the U.K., Spain, and Italy. That percentage should decline over 2023, on average, though Germany and swathes of Eastern Europe will expand gas-fired generation to replace coal and lignite. We expect wholesale natural gas prices in Europe to remain high, by historical standards, and comfortably above $10 per thousand cubic feet (mcf) until the winter 2025-2026. After that, prices are likely to come under pressure from the steady expansion of global liquefaction capacity. That expansion will occur particularly in the U.S, which could nearly double its LNG export capacity to some 240 billion cubic meters annually by 2028 (about equivalent to Europe's total annual imports), and in Qatar.

Regulations that maintain current market functioning and thus natural gas's role as a key determinant of base-load prices.   A March 2023 proposals from the European Commission (EC), as well as regulations in the rest of Europe, are designed to support renewables investments with new payment and contract structures. Yet the current draft of the EC regulation will also entrench gas's role as the most expensive input in the power hierarchy and thus as the power price setter for at least for the next two to three years (see section on rules below). Merchant generators will thus remain exposed to market price volatility.

Currently sluggish renewable capacity installation.   The effect of the acceleration of investment in renewables (and particularly solar) won't really begin to bite until the second half of the decade due to the typical two to three year delay between investment decisions and commissioning.

Decommissioning of coal and nuclear capacity as well as the sluggish rebound in French nuclear output.   Increased renewable capacity's effect on overall power output could be muted by the continued phasing out of European coal plants and the shuttering of nuclear reactors in the U.K. and Spain (following the removal of a net 3.5 gigawatts (GW) of nuclear capacity in Germany and Belgium between September 2022 and April 2023). At the same time French nuclear generation has dragged on supply as it struggles to recover from a three-decade low in 2022.

Sustained high carbon dioxide prices.   The price of emission allowances (EA) in both the U.K. and the EU has about quintupled, to about €80-€100 per ton, over the past two years and is unlikely to fall significantly going forward, according to S&P Global Commodity Insights. Those costs can be significant and feed directly into baseload prices.

The Coming Cliff

While we expect baseload prices to remain strong through 2025, risks to that outlook can't be discounted (as the events of 2022 proved). European utilities seem, however, better prepared to deal with shocks, including due to more robust liquidity arrangements and the introduction of government backstops for systemically-important participants in the energy derivative market. Meanwhile, additional global LNG capacities could leave wholesale gas prices in the single-digit range (on a $/mcf basis) , from winter 2025-2026. That would be about 8x lower than in autumn 2022, meaning gas will be both less relevant to power prices and cheaper anyway.

S&P Global Commodity Insights power prices forecast is for a 30%-60% fall in baseload prices across the E5 over the five years to the end of 2030. That decline will come despite sustained electrification of demand (see chart 2) and rangebound EA prices. Furthermore, it will extend beyond the E5, albeit with some variations in intensity, facilitated by Europe's continued buildout of interconnector capacities.

Chart 2

A fall of that magnitude will leave prices at about €35-€50/MWh across much of the region--with the likely exception of Italy (see Italy section below). While prices at those levels were not unusual during the 2010s, utilities are likely to now feel their impact more acutely due to higher inflation: which is particularly weighing on renewables and networks capital expenditure (capex), and which already constrains our assessment of utilities' credit worthiness due to pressures on their mid- to long-term free cashflow generation.

It is not only lower average prices that will prove a burden for utilities. Intra-day and intra-season volatility is also likely to increase--providing increased cashflow uncertainty. S&P Global Commodity Insights forecasts that European market prices will be below €10/MWh about 25% of the time by 2030, and potentially more than 50% of the time by 2035, compared with less than 5% today (see "EU's Proposed Energy Market Redesign Mitigates Merchant Risks And Accelerates Renewables," published April 3, 2023). Furthermore, we expect the typical average price decline that occurs during April-June (when demand is low) to increase from 10%-15% in 2024 to about 25% in 2025, and to about 40% in the following years. That discount will particularly affect wind and (even more) solar generators, whose output typically peaks during that period.

If investors in renewable capacity (including utilities) have similar expectations, then Europe's capacity buildup may fall short of what is necessary to meet the region's energy transition targets. That could possibly lead to delays that would support prices and utilities' cashflow generation above our base case.

Power Prices Under Pressure Post 2025

The factors underpinning our expectation of a decline in power prices can be broadly grouped into two categories: physical market-dynamics and the impacts of the energy supply mix.

The key elements effecting the physical market dynamics will be:

• Renewable capacity expansion in double-digit percentages on an annual basis. Growth at that rate should easily outstrip increasing demand, even on a net-basis that takes into account the retirement of coal, gas, and nuclear plants (see section below: "Why The Renewable Boom Won't Supercharge Supply"). That supply growth could be slowed by potential bottlenecks around permitting, installation logistics, and timely connection to the grid, all of which have commonly affected European utilities.
• The return of electricity demand growth after two years of decline. We expect demand in the E5 will expand from the fourth quarter of 2023 at an annual rate of about 3% over 2024-2029, resulting in cumulative growth of about 23%. For context, the resulting about 390 terawatt hours (TWh) increase from 2023-2030 (see chart 2) equals current wind and solar production combined. The rate of expansion will vary across different nations, depending on current levels of electrification. Power demand in France, which is already significantly electrified, is expected to increase 10% out to 2030, while electricity demand in Spain and Germany is likely to climb about 30%.
• Accelerating electrification. S&P Global Commodity Insights' demand forecast incorporates an expectation that electrification trends will accelerate, for example due to greater penetration of electric vehicles; incipient (though limited) demand from green-hydrogen electrolyzers, continuing electrification of heavy industries, and a sharp increase in heat pump demand. National policies could provide further demand impetus, for example Germany has a draft law that would mandate that heating for new residential buildings is at least 65% renewable from January 2024.

Cannibalization And The Supply Mix

With regards to supply mix, the key factor will be the so-called renewables cannibalization effect. This refers to the tendency of similar renewable assets to produce simultaneously (for example solar panels on sunny days), leading to output peaks that depress wholesale prices.

As wind and solar increase their share of the supply mix an inflexion point will be reached at which cannibalization can be expected to significantly increase in the percentage of time at which prices are very low. As noted earlier, the percentage of intraday power prices below 10€/MWh is expected to increase to more than 50% by 2035, compared with less than 5% today.

In Europe, that inflexion is likely to be reached soon after the middle of the decade. The impact of cannibalization will be greatest on utilities with significant exposure to wind and solar (particularly in the two biggest solar markets, Germany and Spain). Solar generation has the additional disadvantage of being most productive during sunnier months, when demand is traditionally lower, and when supply is supplemented by additional heat-pump output. The possibility that power transmission grids will struggle with the pace of the renewable generation growth is an additional supply risk and comes with a high potential for input curtailment.

Pricing pressures that are inherent to a greater share of renewables in the energy mix can be mitigated. Most evidently that can be done by developing power interconnections (to shift power to where it is needed), storage alternatives (such as pumped storage capacity or the use of hydrogen as a storage solution), or hybridized renewable generation (which combines production with storage to improve output flexibility).

The flip side of cannibalization is that in periods when the sun doesn't shine and the wind doesn't blow energy supply can dip sharply, pushing prices higher. Generators with flexible output, such as pumped and reservoir hydroelectricity, and gas-fired plants, should be able to take advantage.

Chart 3

General Trends With Regional Variations

While the effects of renewable's rapid growth will be felt across Europe, the particularities of national markets mean experiences across the region will be markedly different--particularly due to variations in the supply mix (see charts 4 and 5) and weather. For example, the north of Europe is likely to favor wind generation, while the south will more readily adopt solar generation, each of which comes with its own pros and cons.

Demand patterns will also play a role. The growing demands of German heavy industry, and energy intensive sectors in the Nordics and Benelux will place different strains on energy markets to those experienced in France, where demand is skewed toward residential heating. For example, In 2021 France's power demand nearly equaled that of Germany's, but by 2030 it is likely to be 20% lower.

Chart 4

Chart 5

Key National Market Characteristics

France

Electricity prices will be determined by the degree to which nuclear generation recovers from outages and by the extent to which gradually increasing renewable generation outweighs tepid demand increases. The country's expected compound average growth rate (CAGR) between 2020-2030 is among Europe's lowest at about 1.4%, or about half the E5's average of 3%.

If French nuclear production returns to its 2021 levels, of about 370 TWhpa, by 2030 there could be significant export capacity to satisfy demand in Italy and Germany, which both should have much higher CAGR.

Italy

Italy is likely to pay a higher price for electricity, compared to other E5, countries out to 2030 and beyond. S&P Global Commodity Insights forecasts prices above 70€/MWh until 2030 (almost double France's forecast of about 35€/MWh).

That premium is due to the country's greater reliance on gas-fired generation and expectations that it will continue to import power (about 80 TWhpa in 2030--or nearly double France's peak exports of 44TWhpa, achieved in 2019).Prices will also be underpinned by a 23% increase in electricity demand over 2023-2030, equal to an expected CAGR of 3%--in line with the E-5's average.

Germany

Already Europe's largest single power market, electricity prices will find some support in the country's expected CAGR of 3.8%, which is the highest in the E5 and will add nearly 140 TWhpa of demand over 2023-2030. On the other hand, since it is also one of the countries raising renewable capacity the most, this will depress prices.

U.K.

Electricity prices will come under pressure in the UK, where a tripling of wind production by 2030, to over 200 TWhpa, will contribute to total generation growth that is 50% above the decline in gas-fired output.

Spain

Prices are likely to come under pressure from rapid renewable growth that will outpace thermal plant closures (including all coal plants and the first nuclear retirements). Solar production could quadruple over 2021-2030 to about to about 100-110 TWh, while wind generation could double to about the same figures.

Spanish demand growth is expected to be moderate, while export opportunities could be curtailed by poor limited (and below EU target) interconnectivity with France.

A Generally Positive Credit Trend In The Short-Term

We expect that all power generators will be broadly subject to similar pricing trends, including a generally supportive business environment characterized by higher prices until the end of 2025, followed by price deterioration out to 2030. We assess how companies analyze and respond to transition challenges as part of our analysis of business risk, financial risk, and management and governance, all of which feed into our assessment of credit quality.

Among the beneficiaries of the current high power-prices could be utilities:

• With stronger-than-expected credit metrics, as was the case with SSE PLC (see "UK Integrated Utility SSE Outlook Revised To Positive On Improved Operating Conditions; Ratings Affirmed" published Dec. 9, 2022).
• Whose strategic visibility has recently improved, as was the case earlier this year with EnBW Energie Baden-Wuerttemberg AG (see "EnBW Outlook Revised To Stable On Improved Credit Metrics Trajectory; 'A-/A-2' Ratings Affirmed," published March 30, 2023), EP Infrastructure (see "EP Infrastructure Outlook Revised To Stable On Reduced Financial Risk And Strong Operating Performance; Ratings Affirmed," published April 25, 2023), Fortum Oyj (see "Finland-Based Power Co. Fortum Outlook Revised To Stable From Negative; 'BBB/A-2' Ratings Affirmed On Strategy Update," published March 9, 2023), and Naturgy Energy Group S.A. (see "Naturgy Energy Group S.A. Outlook Revised To Stable From Negative On Improved Financial Headroom; 'BBB/A-2' Affirmed," published May 30, 2023).
• With strengthening generation profiles, like Teollisuuden Voima Oyj (see "Finnish Nuclear Producer Teollisuuden Voima Upgraded To 'BBB-' From 'BB+' On OL3 Plant Commissioning; Outlook Stable," published April 26, 2023).

Time To Act

Going forward we consider that utilities will retain significant control over the fate of their creditworthiness, even as prices fall, but also believe that the window of opportunity offered by the currently benign pricing environment is closing.

Utilities will have to balance investment in the energy transition, the opportunity for debt repayment, and pressures to reward shareholders. From one company to another that balance may be influenced by legacy assets and current financial profiles.

Potentially credit-quality supportive options include:

• An acceleration of renewables capex, albeit with an eye on the impact of inflation on returns on capital employed.
• Investment in battery storage or low-emission hydrogen, via an electrolyzer, to compliment wind and solar capacity and minimize curtailment.
• A reduction in EBITDA vulnerability to EA prices through early closure of coal-fired assets and by adoption of carbon capture technology.
• The maintenance of flexibility through the blending of baseload, intermittent, and some fossil-fuel based generation (albeit skewed towards low-carbon gas-fired capacity).
• Judicious contracting. While hedges buy time rather than really provide long-term solutions, the EC's March 2023 proposals to require EU member states to ensure availability of counterparty risk guarantees under purchase price agreements(PPAs) could support longer tenors and broader availability of PPAs (see "EU's Proposed Energy Market Redesign Mitigates Merchant Risks And Accelerates Renewables," published April 3, 2023). This could directly help utilities, support the bankability of some of their capacity-builds as project finance, and/or facilitate farm downs and asset rotation. There is a risk, however, that PPAs signed at high prices will come under pressure to be renegotiated once prices fall later this decade.
• Reduction of financial leverage, not least due to the containment, and possibly reduction, of shareholder distributions. Significant differences have emerged in how companies are allocating funds from operations (FFO) and operating cash flows to capex, dividends, and debt reduction. We consider those differences to be indicative of management priorities, while ensuing effects on key credit metrics, including FFO/debt and debt/EBITDA, could be key determinants of credit worthiness.

The range of those options, not to mention the variations within them, suggest the complexity of the challenges faced by Europe's utilities as they juggle the transition to renewable energy that will transform not only their operations but the entire electricity market.

Decisions made today will have long lasting impacts, and could be keenly felt in the nearer-term as prices turn down from 2026 onward. Management will want to take care to make the right choices. But they shouldn't take too long, the clock is ticking.

Related Research:

Sector wide research:

• Three Northern European TSOs Ratings Affirmed As Congestion Income Is Broadly Credit Neutral; Outlooks Remain Stable, April 14, 2023
• EU's Proposed Energy Market Redesign Mitigates Merchant Risks And Accelerates Renewables, April 3, 2023
• Renewable Energy In Spain: Government Has Yet To Finalize Regulatory Subsidies, April 3, 2023
• EMEA Utilities Outlook 2023: Germany And Austria | A Testing Year For Credit Quality, Jan. 27, 2023
• EMEA Utilities Outlook 2023: United Kingdom | Tailwinds For Energy, Cross-Currents For Water, Jan. 24, 2023
• EMEA Utilities: Credit resilience amid stormy waters, January 23, 2023
• EMEA Utilities Outlook 2023 France, Italy, And Spain | Credit Quality To Withstand Fiscal And Regulatory Intervention, Jan. 19, 2023
• Spanish Electricity And Gas Regulatory Frameworks: Mostly Supportive, Jan. 16, 2023
• EMEA Utilities Outlook 2023 Eastern Europe | Credit Resilience Despite Increasing Affordability Concerns, Jan. 12, 2023
• Eastern European Utilities Handbook 2023, Jan. 5, 2023
• U.K. Electricity Generator Levy Improves Visibility For The Sector, Nov. 22, 2022
• EMEA Utilities: Regulation And High Prices Offset Affordability And Dividend Risks, Nov. 14, 2022
• Europe's LNG Focus Can Bring Pain As Well As Gain For Utilities, Nov. 9, 2022
• What Europe's Energy Redesign Might Mean For Its Power And Gas Markets, Sept. 13, 2022
• Energy Transition: Renewables Remain The Cornerstone Of Future Power Generation, July 20, 2022
• U.K. Utilities Handbook 2022, March 15, 2022

Company-specific:

• Uniper Outlook Revised To Stable On Return To Profitability; ‘BBB-’ Rating Affirmed, June 19, 2023
• Naturgy Energy Group S.A. Outlook Revised To Stable From Negative On Improved Financial Headroom, 'BBB/A-2' Affirmed, May 30, 2023
• Tear Sheet: Engie, May 12, 2023
• Finnish Nuclear Producer Teollisuuden Voima Upgraded To 'BBB-' From 'BB+' On OL3 Plant Commissioning; Outlook Stable, April 26, 2023
• EnBW Outlook Revised To Stable On Improved Credit Metrics Trajectory; 'A-/A-2' Ratings Affirmed, March 30, 2023
• EDF Affirmed At 'BBB/A-2' As Stronger State Support Mitigates Operational Issues And Debt Growth; Outlook Stable, Dec. 14, 2022.
• U.K. Integrated Utility SSE Outlook Revised To Positive On Improved Operating Conditions; Ratings Affirmed, Dec. 9, 2022
• Italian Energy Company Enel SpA Affirmed At 'BBB+/A-2'; Outlook Negative On Limited Headroom For Execution Risk, Dec. 7, 2022
• Iberdrola S.A. 'BBB+/A-2' Ratings Affirmed On Updated Strategic Plan; Outlook Stable, Dec. 1, 2022

Writer: Paul Whitfield