Europe's energy woes have increased the urgency for a massive expansion of RES generation capacity. On March 14, the European Commission proposed revisions to various EU electricity laws to achieve just that. Its proposals aim to better shield consumers from price volatility and allow for reliable supply. The European Parliament and Council still need to discuss and agree on the proposals, which could be implemented before the end of the year.

The reform plans will leave the marginal pricing signal of wholesale power markets unchanged. The proposed extension to the entire EU of two-sided CfD schemes for renewables (beyond countries where they already exist), plus more-market-based PPAs with a guarantee mechanism to protect electricity generation companies from offtaker counterparty risk, should support more stable remuneration for RES project assets. This is an encouraging development for the Commission's ambitious REPowerEU plan, which foresees an increase in installed generation capacity from RES (primarily wind, solar and hydro) to 1,236 gigawatts (GW) by 2030, from 513 GW in 2021.

As a result, we expect that, by 2030, the majority (50%-55% or 63% including hydro) of Western Europe's electricity will stem from wind and solar generation, up from about 26% this year and 20% in 2019.

Chart 1

Supply: The CfD Mechanism Strengthens Price Visibility For Developers

Yet the proposed two-sided nature of CfDs will be less attractive to sponsors than the feed-in tariffs or one-sided CfDs used in some countries. This is because this requires electricity producers to give back to consumers revenue above the agreed strike price (or upper strike price if there is a corridor mechanism). That said, CfDs are still the most credit-supportive offtake agreements because they take away not only the uncertainty of long-term market prices but, in the case of renewables, also the risk of intraday price fluctuations. In addition, the counterparty of a CfD is usually the end consumer or the government, rather than a specific entity as is typically the case for PPAs.

Because the uptake and strike prices of CfDs are set through competitive auctions, one constraint to these CfDs may be the maximum strike price each national authority is willing to accept. This, together with supply bottlenecks and other factors, have meant that recent CfD auctions saw only a moderate portion of volumes being subscribed. Rather than a subsidy, CfDs that provide 15- to 25-year contractual protections can be seen as a swap of spot to fixed prices. The absence of major subsidies is credit supportive because it may alleviate the risk of future contract revisions or regulatory pressure.

CfDs may however involve credit issues that need to be taken into account, such as:

• Conditionality, as we understand the proposed CfD mechanisms may not apply to periods when market prices are zero or negative. If that's the case, there would be some degree of market exposure, more for price cannibalization-prone wind and solar generation than, for example, hydro or nuclear. The latter situation would require more in-depth risk analysis of future power prices precisely because the number of such low-price periods will rise in the future (see also chart 5).
• Generation curtailment, since in some countries only a portion of CfDs may be paid as long as grid connections represent a bottleneck, or there may be a risk of higher future curtailment rates during periods of excess wind or solar power generation.

Demand: Appetite For Market-Based Corporate PPAs Will Increase

European corporates have stepped up PPA contracting efforts, as a result of which we anticipate a rise in volumes delivered under such PPAs in the coming years. Current contractual PPA volumes are highest in the Nordic region and Spain, followed by Germany and the Netherlands (see chart 2).

Chart 2

Looking ahead, S&P Global Ratings expects a further strong rise in RES PPAs as corporate power users seek to hedge more efficiently against short-term price volatility and advance their sustainability agendas. For instance, European companies that have joined the RE-100 renewable energy initiative have upped their RES procurement targets to 75% by 2027 from 44% in 2020 (see chart 3).

Chart 3

A key benefit of the Commission's proposal for PPAs we believe is that it seeks to address the counterparty credit risks of buyers by obliging member states to ensure the availability of market-based counterparty guarantees. To date, project developers and financiers would likely accept only highly creditworthy counterparties for long-term contracts of 10-25 years. Having a guarantee-mechanism could thus allow more corporates to enter into PPAs as well as extend their tenors.

PPA-Backed Projects Still Face Several Other Risks

Even if counterparty risks were removed, various risks--specific to PPAs and PPA-based project financing--would still need to be addressed. These include:

• Whether contracted volumes contain any minimum monthly or yearly commitments. Even if we assessed the risk of not meeting such commitments as remote, the obligation to buy volumes in potentially volatile spot power markets may expose the power producer to material price risk. This is notably because any major shortfall of wind or solar resources will in the future most likely cause a spike in power prices.
• Whether RES contracted volumes are on an as-produced basis or involve balancing requirements, meaning guaranteed volumes on a given day or hour. Since wind and solar do not represent a dispatchable power source, we would expect contracting such balancing services to be the buyer's responsibility or involve reliance on incumbent utilities (such as via tripartite agreements). In our understanding, the cost of such balancing services used to be limited. But we imagine it will become more costly and complex to fix the price for such services over long periods, as gas- and coal-fired capacity comes to represent a smaller share of the energy mix.
• Price-related risks, notably if a fixed-price PPA contained reopeners or exit options for offtakers. Mark-to-market exposures and renegotiation risk by offtakers will rise with longer-term PPAs, should future power prices drop below the PPA strike price. Furthermore, PPAs may be designed with prices set under a collar or indexed to an average rather than a spot price.

Predicting RES Power Price Capture Rates Is Becoming Even More Complex

We expect the majority of RES project financings to minimize exposure to wholesale market prices through CfDs, PPAs, or both. This may nevertheless involve some elements of market exposure. For instance, the tenors of PPAs are likely to cover only part of a project's useful life. Also, existing RES projects may come off prevailing CfD regimes. With the bulk of capital already amortized, creditors may be willing to accept some merchant risk after the CfD ends. In our view, extra caution is needed when analyzing long-term power prices and, in particular, the actual power prices realized by the RES project (that is, the capture rates). This is because:

Forecasting power prices remains extremely difficult, with higher volatility than for any other commodity.   In view of the envisioned structural change in Europe's energy market, we cannot rely on modelling power prices using historical correlations. We also see, for instance, that electricity forecasts have been quite volatile over short periods of time (see chart 4). Changes to the front of the base-load price curve are explained by the extreme volatility of gas prices over the last year. However, even long-term price forecasts are subject to meaningful variations because they depend on the pace of RES growth and their levelized cost of energy, but also on future market dynamics and policy assumptions.

Chart 4

Increasing low marginal-cost RES generation could push down base-load prices and exacerbate price volatility.   The rising share of low marginal-cost renewables tends to support a long-term decline in power prices in real terms. In the EU, the latter will continue to be determined by the highest-marginal-cost producer that enables supply to meet demand (E.U. initiatives unveiled March 14 exclude a market split). We equally expect to see more extreme price variations between periods with low renewable output, with prices set by the cost of gas-fired generation or other dispatchable power sources, and periods of abundant renewable output. 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 chart 5).

Chart 5

These estimates may however evolve, depending on future policy changes, to build in greater resilience through adequate back-up capacity of firm power in markets and, in the long term, the extent of electrolyzers and resulting use of hydrogen as a power source. Besides this, more flexibility measures will be needed, such as stronger demand signals, battery storage additions, and potential for more RES supply curtailments. We would also need to monitor the potential for climate-related changes to long-term hydrology patterns and the resulting flexibility from hydro power, which accounts for more than 10% of Western Europe's generation output.

Moreover, pure merchant renewables will be exposed to price cannibalization, since renewables, notably solar, have similar generation profiles.   Price cannibalization risk refers to the risk that the average price captured by a merchant RES project is materially lower than the average daily base-load price (see chart 6). This risk arises due to excess power supply from strongly correlated wind and solar generation sources.

Chart 6

Such erosion of the capture prices is less of a risk for geographically diverse portfolios of wind farms, since wind speeds in one area may only be moderately correlated with those in other regions. By contrast, solar loads are highly correlated within and across European countries and highly concentrated during midday hours, explaining their lower unit-capture price than the average base-load price. Also, the difference between these two prices looks set to widen in relative terms as the share of renewables surges, unless sufficient battery or hydrogen capacity comes on stream. This has already happened in California, where electricity prices may--under certain circumstances--reach zero during daylight in the summer, which in turn has triggered significant investment in battery storage.

Limited Merchant Risk Could Potentially Be Consistent With Investment-Grade RES Projects

Given the daunting task of forecasting long-term base electricity and intra-day capture prices, a renewables project that is fully exposed to wholesale prices is unlikely to achieve investment-grade credit quality unless, potentially, leverage was very low. However, low leverage would imply a project that's likely not economically attractive to sponsors.

We nevertheless foresee that some projects may have limited merchant exposure and still achieve an investment-grade rating. An example is WindMW GmbH's wind offshore project in the north of Germany, which is rated 'BBB-'. The project has a regulated feed-in tariff until 2027 and about 90% of the issued debt will have been repaid by that time. Afterward, the project becomes exposed to power prices. During this "merchant tail" its debt-service coverage ratio (DSCR) increases to about 2.2x (see "WindMW GmbH Senior Secured Debt Affirmed At 'BBB-'; Outlook Stable," published Feb. 25, 2022). In addition, WindMW has the option of selling electricity under its regulatory regime until 2034 at a floor price, coupled with a forward-looking cash reserve mechanism that is based on forecast power prices.

While we have seen technology risk decline and we have access to generally reliable statistical studies to analyze wind and solar resource risks, we believe forecasting power prices and their volatility remains subject to significantly greater uncertainty. Hence, despite solar and wind projects' intrinsic ability to generate free cash flow in view of their very low marginal production costs, we would expect projects with merchant risk exposure to have investment-grade potential only if they benefit from material mitigating factors. These may include one or a combination of the following:

• Partial protection from CfDs and/or PPAs, allowing for predictable repayment of a significant share of the project debt before the project has a merchant tail.
• Absent a fixed price, some kind of minimum floor price or price corridor mechanism under a PPA or regulatory mechanism (see "The End To Subsidies: The Beginning Of A New Era For Spanish Renewables?," Feb. 7, 2018).
• Limited exposure to balancing risks, which are absorbed by the offtaker and/or contractually outsourced to a creditworthy utility.
• Significantly higher base-case DSCRs during the merchant tail and resilient DSCRs higher than 1x under conservative price-downside scenarios or, if lower, continued debt service over a prolonged period of stress supported by strong liquidity features.
• Strong liquidity with above-average debt-service reserve accounts.
• Flexible debt repayment structures to manage price volatility, including during the year, in addition to resource variability. This may entail cash sweep mechanisms to pay down debt faster in more profitable years.

Merchant risks of RES projects for independent power producers (IPPs) obviously differ from those utility companies face. Utilities not only have strong balance sheets and large diversified generation operations but can also pass on merchant price risk through their integrated retail services. The possibility of corporate PPAs as per the Commission's proposal may help close the gap between RES projects and IPPs.

Merchant Solar And Battery Projects Have Price Forecasting Hurdles

We expect merchant-exposed solar renewables projects that combine battery storage will benefit from the ability to dispatch during peak price periods and thus capture better prices to offset the significant extra investment costs. Forecasting average peak wholesale prices is however subject to similar, if not higher, complexity than the base-load capture rates for solar projects without batteries. Moreover, for our analysis, we would need to factor in additional risks, such as the battery life, its capacity declines, and replacement cost, since its life is shorter than that of a solar photo-voltaic plant.

Hydro And Geothermal Merchant Projects Will Be In A Better Credit Position

Solar and wind projects differ from dispatchable hydro- or geothermal power projects in that they can more easily achieve investment-grade credit quality, even when facing merchant risk. This is because dispatchable hydro plants (dams rather than run-on-river operations) have long-term storage ability, allowing them to optimize price realizations.

They also have a scarcity value, coupled with the geographic attributes required for the location of hydro assets. In addition, hydropower assets tend to benefit from a longer operational life, with limited annual maintenance. This reduces the need for large capital overhauls every seven to 10 years and also helps mitigate tail merchant price risks. An increasing risk factor though lies in the forecasting of long-term shifts in hydrology conditions due to the impact of climate change.

We see examples in North America that also illustrate the value gap between firm and intermittent renewable power. In the U.S., some geothermal assets are fetching contractual prices estimated at over $65/MWh, compared with a mere $25/MWh offered under some as-produced solar power long-term contracts.

Related Research

• Energy Transition: Renewables Remain The Cornerstone Of Future Power Generation, July 20, 2022
• Going With The Flow: The Competitiveness Of Battery Storage Economics In the Power Sector, Feb. 4, 2021

External Research

• Commission proposes reform of the EU electricity market design to boost renewables, better protect consumers and enhance industrial competitiveness https://ec.europa.eu/commission/presscorner/detail/en/IP_23_1591
• REPowerEU: A plan to rapidly reduce dependence on Russian fossil fuels and fast forward the green transition, European Commission, May 1, 2022