Demand for Environmentally Friendly European Power Assets Risks Weakening Credit Profiles

KBRA Research

09 November 2021

Kroll Bond Rating Agency Europe Limited (KBRA) has observed several converging trends that place a spotlight on merchant risk in European renewable project finance. Incentives provided for environmental, social, and governance (ESG) projects have encouraged the development of a competitive market by subsidising pricing as well as driving developments in the funding markets through demand on the investor side. KBRA believes the combination of supply and demand factors for merchant-exposed transactions in the project finance power markets creates an environment that fosters an increase in the number of project finance transactions more directly exposed to the power markets and risks weakening credit profiles without effective structural support.

Key Takeaways

Factors that influence the quality of projects (supply) and their exposure to power market risk include: (i) the phasing out of renewable energy subsidies by European governments, (ii) lower pricing support provided by contracts for difference (CfDs) as auction prices decrease, and (iii) a rise in the number of renewable energy projects.
Factors influencing the demand for project finance transactions, which in turn further increase the exposure to power markets, include: (i) investors increasingly chasing ESG-focused assets with renewable energy style funding, (ii) supplier demand for renewable energy projects to meet demands from clients, and (iii) financial innovation to meet the need for higher yields from investors.

These factors have created an environment that is increasingly exposed to power price volatility, refinancing risk, and liquidity risk. This raises questions around renewable project financing credit risk and how it is mitigated. In this report, we outline the various factors at play and how funding methods are adapting to these risks.

Factors Impacting Supply of Merchant-Exposed Transactions

As the supply pipeline for renewable projects continues to grow, renewable project finance transactions entering the European market are increasingly exposed to merchant risk and variability of power markets. This is principally due to the success of the efforts to subsidise the development of renewable projects. However, the once heavy subsidies for new projects are no longer needed to support the expansion of the market. As a result, the phasing out of this support is impacting the credit profile of new transactions.

EU Subsidy Schemes Phase-Out

Various schemes and subsidies were key to the development of the European renewables sector, although this support has come at a cost for governments and consumers. These subsidised schemes helped to facilitate the rapid expansion of renewable electricity generation, which was accompanied by advances in technology and knowledge, and the subsequent lowering of costs. This can be seen in the lowering of levelised costs of energy across the various types of renewable energy (see Figure 1).

European governments have phased out the more expensive schemes. In Germany, the Renewable Energy Sources Act  or EEG (Erneuerbare-Energien-Gesetz) originally provided a feed-in tariff (FIT) to encourage the generation of renewable electricity. This 20-year subsidy scheme has now started to roll off, although the sale of green certificates continues to offer some level of support. The UK’s FIT scheme for small-scale renewables closed in March 2019 and was replaced in January 2020 by the Smart Export Guarantee (SEG) scheme, which allows small-scale generators to access the grid at tariffs determined by the electricity supplier. Solar photovoltaic generation projects in Spain continue to be backed by regulatory return-on-asset based remuneration, while onshore wind benefits from less certain support mechanisms.

Figure 1: Global Levelised Cost of Renewable Energy by Type, 2010-2019 (USD/kWh)

Global levelised cost of renewable energy by type.png

CfDs in the Power Markets

An important mechanism that has replaced traditional forms of regulatory support for renewables is the contracts for difference scheme. The mechanism, initially introduced in the UK in 2013, was designed to replace the previous Renewables Obligation scheme and provide investors with confidence to invest in low carbon electricity generation by fixing prices based on auctions or bilateral agreements. Under a CfD regime, clean power generators agree to a strike price to be paid by a government or government-sponsored entity in an auction, fixing the income the project will receive from the sale of the electricity generated. While CfDs were originally introduced in the UK, other jurisdictions in Europe such as Spain, Germany, and Denmark have also started to take on this model of support across various renewable technologies (wind, solar, biomass, etc.).

CfD Auction Prices Declining

Figure 2: UK CfD Strike Price, 2017-18 vs. 2019-2020 (GBP/MWh)

CfD schemes have proven to be effective in reducing the government subsidy per MWh of renewable energy generated. For example, in the UK there has been a notable decline in government subsidies per megawatt hour (MWh) in 2021, particularly as power prices have recovered. The difference between the strike and market price has persisted at an all-time low throughout 2021, averaging GBP30 lower than the historical average.

In September 2019, the world’s largest offshore wind project, Dogger Bank Wind Farms, set a new UK record low price of GBP39.65/MWh ($48.80/MWh) as it dominated CfD awards for 6GW of renewable energy. This marked a 30% reduction in offshore wind power costs compared to CfDs in 2017, when the lowest rate was GBP57.50/MWh. A recent example of the reduction in subsidies is the publicly reported Seagreen offshore wind project in Scotland. Seagreen closed in June 2020 due to the COVID pandemic, with only 42% of the energy generated at the wind farms covered by subsidies from the UK government. Furthermore, Spain auctioned off 3GW of renewable energy capacity in its January 2021 tender. For the solar portion, the average price was EUR24.47/MWh (the lowest was EUR14.98/MWh), guaranteed for 12 years through CfDs. This auction also resulted in some of the lowest prices ever seen for onshore wind in Europe.

In KBRA’s view, these developments are likely to result in a higher level of market risk as cash flows become tied to merchant prices for the following reasons:

With lower CfD auction prices, the credit quality of the transaction becomes increasingly predicated on the sponsors’ ability to accurately forecast future power prices.
CfD schemes are typically limited in tenor, with maturity dates determined by the auction process and jurisdiction in question. In contrast, KBRA has observed financing maturities in renewable transactions extend beyond the CfD tenor, which results in a merchant tail.
As CfD auctions become more competitive, there is a perception that in certain jurisdictions such auctions may be creating a “winner takes all” situation, where large-scale developers with stronger balance sheets can outbid smaller and midsize developers. This is leading to the smaller and midsize projects having to increasingly rely on market-exposed cash flows (in the absence of regulatory support schemes such as the CfD) to cover debt service.

Significantly lower CfD strike prices reduce the likelihood of the CfD mechanism being triggered. This results in greater cash flow volatility as the project is more exposed to merchant prices.

Factors Impacting Merchant-Exposed Transaction Demand

Investor Demand for ESG-Linked Assets

The demand for renewable assets is at an all-time high as ESG-focused investors compete for a limited supply of projects. In certain cases, this dynamic is resulting in weaker credit metrics as investors are willing to take on more risk to receive a larger allocation. Many in the investor community, from asset owners to managers, have made ESG-related commitments either directly to their stakeholders or government bodies to support the global transition to a low carbon economy. These ESG mandates will likely continue to result in a strong demand for clean energy assets. While this dynamic is a positive for the development of renewable assets, heightened demand and limited supply may result in weaker credit quality (ie lower DSCRs, higher leverage, full exposure to merchant cash flows, etc.).

Lending and Investment Support From Green Bond Growth

Green bond issuance has rapidly expanded in recent years, with USD227.8 billion issued in first half (1H) 2021, more than double the amount issued in 1H 2020. Most of these bonds are sold on a “use of proceeds” basis, meaning that rather than funding a green investment directly, the issuer agrees to use the funds raised from the bond sale to invest in or support any number of future green projects. This further increases the volume of funds directed towards renewable project finance. For example, a bank issuing a green bond may use the proceeds to lend to a renewable energy project. Alternatively, a government may dedicate the funds to offer more CfDs or invest directly into a renewable project.

Investor Appetite for Yield and Financial Innovation

The transition away from carbon-intensive sectors has accelerated interest in project finance in various ways which, combined with ongoing low interest rates, has reduced the cost of finance. Renewable projects are establishing a longer track record of sustained cash flow generation with limited operational interruption as well as greater visibility around assumed asset lives.

In order to meet investor demand for improved yields on ESG assets, innovative financing structures have been specifically introduced to help justify higher yields for some investors. Some of this financial innovation is associated with greater exposure to market risk, such as the introduction of merchant risk into the tail end of cash flows.

Further, some structures feature debt maturities beyond the life of a CfD on the project. As a result, the lender becomes exposed to the capability of the merchant, including its ability to operate the facility efficiently, given power prices at the time and to meet debt repayments. In addition, some structures also introduce enhanced refinancing risk where the lender is reliant on the merchant and the strength of the project to find additional refinancing to meet some form of remaining balloon payment. This activity also draws on the degree of investor comfort associated with longer asset life assumptions that are based on the developing history for these projects.

In KBRA’s view, the confluence of these supply and demandfactors in project finance creates a market environment that is likely to encourage an increase in merchant-exposed renewable energy transactions. As these transactions emerge, KBRA expects that lenders to the sector may want to consider how to balance a willingness to take on merchant risk return for yield against appropriate risk mitigation measures. While there are several common credit risks associated with renewable transactions including market exposure or dependency on contracted cash flows, KBRA has observed specific risk mitigation techniques designed to counter market exposure on merchant-exposed transactions (see Key Credit Mitigants section).

Assessing European Merchant-Exposed Power Deals: Credit Risks

Merchant-exposed power projects contain many of the risks typically seen in power transactions backed by long-term contracts, such as traditional combined-cycle gas-fired power stations, which formed the mainstay of project finance in the 1980s and 1990s. However, merchant-exposed transactions are associated with greater uncertainty around key credit analytical assumptions (eg the trajectory of power prices) as well as how projects can manage liquidity and refinancing risk.

KBRA’s references to the merchant risk exposure encountered by renewable projects in Europe relate to projects without firm contracted cash flows for all of their power production. Such merchant-exposed transactions exist along a spectrum, from high to low power market exposure. The extreme end of the spectrum (highest merchant risk) would include projects involving a portfolio of hydroelectric power plants or an onshore/offshore wind park whose principle source of cash flow is the wholesale power market for the entire length of the debt tenor. Other projects have varying degrees of merchant exposure that are somewhat less pronounced—a similar hydroelectric portfolio project with a significant proportion of the cash flows underpinned by power purchase agreements (PPA) for all of the debt tenor, for example. Another example would be a project backed by some form of support mechanism (CfD or some other levy) that does not cover the full debt term of the financing and is exposed to some degree of residual tail risk, where cash flows are fully exposed in the tail to power market pricing.

A Change in Project Risk Exposure

Power Prices: The power markets in individual countries have their own dynamics, which are partly a function of their respective energy mix, specific regulations, as well as the extent to which natural conditions are favourable for renewables and support their ability to replace conventional thermal power. While Europe’s power markets are increasingly interlinked, jurisdictions vary in terms of key factors which influence power price trajectories.

Power prices in countries such as Germany and Spain, where there is a transition towards more market-exposed transactions, are influenced by greenhouse gas emissions levels and carbon pricing features over the next 10 years. In contrast, France’s power prices are mostly impacted by the nuclear tariff mechanism, given the country’s high percentage of nuclear production.

Broadly speaking, European baseload power prices are affected by a range of factors, some of which include the marginal price-setter mix (thermal versus renewable), commodity prices (particularly gas), carbon pricing, coal/nuclear dynamics, the energy transition, macroeconomic impacts on supply and demand, as well as the role played by interconnectors.

KBRA also notes that assumptions around the future levelised cost of energy (a measure of the average net present cost of electricity generation for a generating plant), as well as the future energy mix, can have an important impact on how market consultants view the evolution of power prices over the medium and long term.

Liquidity Risk: Management of liquidity is important in market-exposed renewable transactions. Debt payments need to be serviced as scheduled irrespective of the prevailing average power price over the period. If there is a short and sharp deterioration in power prices over a specific period, projects will need to mitigate this in some way to avoid issues with cash flow generation to service the debt on time and in full. As the proportion of renewables on the grid increases compared to non-renewables, European baseload power prices are experiencing increased volatility, as highlighted recently following the current spike in gas prices, partly due to low wind power generation. This broadly reflects the influence of seasonality on renewable production. For example, Norway is heavily reliant on hydroelectric power in the energy mix, with precipitation levels across a specific period having an outsized influence on the average power price for that month, quarter, or semiannual period. In the UK, gas storage capacity is limited, and with an increase in renewables such as wind in its power mix, the country can be exposed to low wind levels, which it has experienced recently. KBRA expects this phenomenon of increased volatility (as well as periods of negative pricing over intermittent periods when renewable production exceeds demand) to continue as more renewable sources of electricity enter the system.

Refinancing Risk: As investors and lenders gain greater comfort with asset life estimates, KBRA has observed some renewable transactions with reduced levels of amortisation over the transaction life and increased reliance on the ability to refinance at debt maturity. Such refinancing risk exposure can be complicated on merchant-exposed transactions that do not have viable options for obtaining contracted cash flows at the time of maturity (irrespective of the asset life) and/or due to a lack of certainty around future power price assumptions for that particular market post-maturity.

Key Credit Mitigants

Renewable energy developers in Europe are relatively confident in accepting lower CfD awards, as well as less direct government support or regulated revenue, based on their assumptions of how power prices are likely to evolve and what this will imply for cash flow generation. However, to provide lenders and investors with comfort that such transactions have acceptable risk profiles, KBRA has observed the following actions taken by sponsors intended to counter merchant exposure:

Higher Coverage Ratios: Cash flow volatility in market-exposed projects has been generally mitigated by targeting higher coverage ratios than in transactions that benefit from contracted cash flow streams. For example, it is not uncommon to find the same sponsors presenting transactions to the market with average debt service coverage ratios (DSCR) ranging from 1.7x to 2x on predominantly merchant-exposed transactions compared to average DSCRs ranging from 1.2x to 1.4x on fully contracted renewable transactions, all things equal. The market will likely require these buffers to be maintained under conservative power price, operating, cost, and financing assumptions over the life of a transaction. Further, KBRA has observed a differentiation between transactions that have partially contracted revenue streams versus those that are fully exposed to merchant risk in terms of DSCR levels. KBRA notes that for periods where “hybrid” (part market/part contracted) merchant-exposed transactions have some element of their cash flow hedged, then DSCR levels have been allowed to reduce relative to periods where the transaction is fully exposed to market risk.
Liquidity Buffers: A variety of reserve techniques such as the buildup of sinking funds over the life of a transaction or cash traps/cash sweeps (in addition to standard debt service and maintenance reserves) are often used to help alleviate the impact of short, sharp price fluctuations on cash flows. Cash balances may also be set aside at financial close and made available over the term of the debt. These accounts can help mitigate the risk of a sharp deterioration in cash flows in markets that are prone to large swings in power prices over short periods.
Robust Breakevens: Sponsors are aware that lenders and investors increasingly look to break-even metrics to help assess the credit profiles of merchant-exposed transactions. This may involve comparing the break-even price for a transaction against the lowest historical prices observed over one or two economic cycles or even decades. For lenders who are more cautious about the evolution of power prices in the longer term, break-even techniques can also include a comparison with medium- and long-term conservative power price forecasts. As such, sponsors have sought to demonstrate their transactions can withstand material wholesale power price stresses and still cover debt service over the lifetime of the transaction. In order to demonstrate healthy breakevens, sponsors may also reconsider what is an appropriate capital structure (level of debt versus equity).
KBRA notes that lenders and sponsors’ stress scenarios may have become more stringent when taking into account recent market data capturing the impact of COVID-19 on price trajectories in different jurisdictions. KBRA notes that market consultants’ assumptions around future levelised cost of energy as well as the energy mix going forward (renewable versus thermal derived energy) can impact future sponsor price assumptions in base and downside cases. Transactions that demonstrate healthy breakevens can differentiate themselves in terms of creditworthiness as future market prices demonstrate potential for greater volatility than historically observed.
Refinancing Capability: Where refinancing risk is present in a transaction, sponsors are generally aware that lenders will look to assess the ability of the transaction to withstand the impact of low power prices on future cash flows at the time of refinancing. Market participants will often use techniques such as discounted cash flow analysis to assess the net present value of future cash flows that can be generated by the project over the remaining asset life. They perform this analysis under conservative discount rate conditions to see whether these are sufficient to meaningfully cover residual debt outstanding at the point of maturity. For merchant-exposed transactions, lenders and investors may sometimes consider potential future offtake/PPA arrangements. However, the likelihood of these materialising is uncertain, and therefore require analysis of a project’s cash flow generation capability under conservative market price conditions up until the end of the asset life.
Portfolio Diversification: Portfolio diversification can be achieved by adding multiple assets under a single financing. This is a common feature of market-exposed utility scale transactions across solar, wind, and hydroelectric power. Moving away from utility scale transactions, KBRA considers a potential for more residential and community-scale capital market transactions to emerge in the renewable space in Europe. There is less evidence of capital market financings of solar rooftop, distributed solar, and community solar structured in Europe compared to markets such as in the US, where this form of financing is more developed. However, Europe has the potential to develop this form of financing and add benefits of portfolio diversification. This could happen with the support of policy initiatives such as the European Green Deal.
Hybrid Technologies: Increasingly, KBRA has observed transactions that include a variety of renewable technologies, some of which are supported by contracted cash flows and others exposed to merchant risk. This trend is likely to continue as storage-related assets or conventional gas-fired assets (with long-term PPA contracts) are financed alongside more intermittent renewable generating assets. Diverse revenue streams can help reduce volatility associated with merchant risk transactions.

Corporate Power Purchasers

In addition to the above factors, KBRA notes that where government support is not available, projects can find commercial counterparts willing to step in and provide a substitute to lock in a portion of future cash flows for a fixed price. These place a special focus on the way in which merchant-exposed transactions may improve their creditworthiness by entering into corporate PPAs with commercial entities.

In jurisdictions such as Norway where much of the power generation is generated without government support, such corporate PPAs are favoured as they provide lenders and investors greater visibility and transparency over part of the cash flows linked to the transaction financing. They also help to smooth the volatility of metrics over the transaction life. Such commercial counterparties may be incentivised to enter into bilateral arrangements with power developers for the purpose of securing supply of power. Further, it can help them to meet certain ESG-related targets by demonstrating a renewable source of power.

KBRA notes that corporate PPA only provides a partial hedge for many of these renewable transactions, with an important degree of cash flow still exposed to market risk. The corporate PPAs typically have defined tenors that are not always as long as the tenor of the financing, which introduces merchant tail risk. Further, such corporate PPA transactions introduce counterparty credit quality risks. If the purchaser is no longer able to make payments for the supply, the project may become exposed to market pricing. However, growth in European corporate PPAs is likely to be limited by the scarcity of creditworthy offtakers. KBRA considers an analysis of corporate PPA terms and conditions will increasingly become an integral part of future credit analysis for hybrid renewable transactions going forward.

While many of the above credit risk mitigants are being addressed in financing structures put forward by sponsors linked to market-exposed transactions, KBRA notes that the potential exists for credit rigour to slip. If pricing conditions remain tight for renewable transactions and/or if the supply of transactions is insufficient to meet the demand, then the potential exists for credit risks to emerge. The latter would involve asset-hungry debt buyers investing in market-exposed transactions that satisfy ESG and yield requirements but are distinctly lacking in sufficient credit rigour that can help mitigate the market exposure. Should this scenario occur, it could lead to a distortion in pricing of market-exposed renewable transactions relative to their inherent credit risk.

Conclusion

KBRA expects to see growth in market-exposed transactions driven by increased supply and investor demand. Renewable project financing is matching the increased demand for renewable power generation with the demand from investors to find ESG-related investments. The phasing out of government subsidies is being matched by a willingness of debt buyers to take on higher levels of market exposure in the sector. Market-exposed transactions in the renewables powersector share many of the risks of conventional power generation, although with greater exposure to power price volatility, liquidity, and refinancing risk due to price uncertainty.

While many of the credit risks in market-exposed renewable transactions are being addressed in financing structures put forward by sponsors, the potential exists for credit rigour to slip. This can happen if an asymmetry emerges between the demand for market-exposed ESG-linked renewable generation transactions relative to supply of market-exposed transactions that are expected to come to market.