Foresight | Macro Trends
Re-evaluating the investment characteristics of unlisted renewable energy investments
May 19, 2023 20 Minute Read Time
Overwhelming policy support for clean energy investment means that renewables and the broader energy transition segments will see more capital deployed and energized project pipelines. Our first article highlighted the public policy push globally to deploy renewable energy faster and why we believe this will expand the opportunity set for infrastructure investors. Besides ESG credentials, many investors in unlisted infrastructure regard operational renewable energy assets as part of a core, low-risk strategy, but has the sector delivered? In this second part of our series on renewables investing, we examine the stability and predictability of renewable energy investments, and how they compare to other core infrastructure assets.Brownfield renewables projects are cash-yielding but are heterogenous assets with a host of operational risks and a higher dispersion of return than core assets such as regulated networks. This calls for a careful analysis of individual transactions coupled with more sophisticated strategies to reduce portfolio risk. While renewables can lower a portfolio’s sensitivity to economic growth and commodity prices, they have relatively high exposure to changes in interest rates. In the current environment of steep base rate hikes, the returns on unlisted renewable energy investments will depend on the continuing ability to access financing at attractive rates.
When it comes to demand, purchase power agreements for renewable energy are appealing to many stakeholders seeking to satisfy their net zero objectives. There are instances, however, of renewable energy from wind and solar taking a demand hit. In 2020, the reduction in demand was due to pandemic restrictions, but was milder for renewables than for conventional power generation (figure 1). As another example, in countries with high renewables penetration, electricity grids are unable to fully accommodate the intermittent renewables load.
Asset managers increasingly leverage technology such as advanced artificial intelligence (AI) techniques to benchmark asset performance and identify the root causes of performance issues. To smooth revenue volatility, some renewables projects are nowadays bundled with energy battery storage. Batteries have seen a remarkable decline in costs by more than 30% to $150/MWh (estimated average)2 over the last decade. In the U.S. and Canada, investment tax credits will further enhance their cost competitiveness.
Cash yielding, but diverse, investments
Infrastructure investors expect recurrent and predictable dividend streams from their investments. On this dimension, both unlisted renewables and regulated network utilities demonstrate a track record of consistently high dividends. In the period 2008 to 2021 they returned on average about 60% of their free cash flow to equity as dividends.
If we dive further into performance metrics, we observe that global renewables are a more heterogenous sector than regulated networks. Their expected returns vary from 6%-10% (first and third quartile) while regulated utilities have a much narrower band. This is likely explained by two reasons. First, renewables projects included in the dataset have some development/construction risk. Development capital offers higher returns but requires investors to take on the risk of site selection, environmental studies, construction permits and grid interconnection.
Second, the revenue mechanism varies significantly across jurisdictions. When it comes to price, most renewables projects of the early vintages had 15- to 25-year fixed subsidies. Over time, as the underlying technologies developed, fixed and indexed feed-in subsidies were gradually replaced by competitive tender mechanisms and the use of market-based solutions such as feed-in premiums and green certificates.
As discussed in our first article, the exposure of renewable developers to merchant power prices has increased, making the revenue streams of some projects less predictable. According to the report by WindEurope/ SwissRe, by 2030 only 6% of European wind capacity—from 75% in 2017, will be fully protected through subsidy schemes. The vast majority of wind projects will operate under mechanisms partially exposed to the market, with up to 10% of new capacity having full merchant exposure.
Are brownfield renewables really core?
We define core infrastructure as the lowest-risk investment strategy—pursuing assets with low volume risk, long-term predictable cash flows, resilience to an economic downturn and significant income yield as part of total return. In our analysis, we assess unlisted global renewables in EDHECinfra’s database based on 130 unlisted renewable energy projects globally (101 wind and solar assets, the rest a combination of hydro-, biomass-generation and battery storage). We compare renewables along the stated dimensions against regulated networks, often seen by the market as the most stable assets under a relatively gold-standard regulation.Stable revenue growth over time with less downside protection
Unlisted renewable energy assets exhibit relative revenue stability over time which is closer to regulated networks than conventional (fossil-fuel) power generation on measures of dispersion. However, renewable energy production is dependent on weather patterns (a higher risk for wind generation than solar) and to a smaller extent, demand factors. According to a report by WindEurope and Swiss Re, wind asset owners need to provide for +/-10% variation of their annual wind production and factor in a high degree of seasonality.1When it comes to demand, purchase power agreements for renewable energy are appealing to many stakeholders seeking to satisfy their net zero objectives. There are instances, however, of renewable energy from wind and solar taking a demand hit. In 2020, the reduction in demand was due to pandemic restrictions, but was milder for renewables than for conventional power generation (figure 1). As another example, in countries with high renewables penetration, electricity grids are unable to fully accommodate the intermittent renewables load.
Asset managers increasingly leverage technology such as advanced artificial intelligence (AI) techniques to benchmark asset performance and identify the root causes of performance issues. To smooth revenue volatility, some renewables projects are nowadays bundled with energy battery storage. Batteries have seen a remarkable decline in costs by more than 30% to $150/MWh (estimated average)2 over the last decade. In the U.S. and Canada, investment tax credits will further enhance their cost competitiveness.
Cash yielding, but diverse, investments
Infrastructure investors expect recurrent and predictable dividend streams from their investments. On this dimension, both unlisted renewables and regulated network utilities demonstrate a track record of consistently high dividends. In the period 2008 to 2021 they returned on average about 60% of their free cash flow to equity as dividends.
If we dive further into performance metrics, we observe that global renewables are a more heterogenous sector than regulated networks. Their expected returns vary from 6%-10% (first and third quartile) while regulated utilities have a much narrower band. This is likely explained by two reasons. First, renewables projects included in the dataset have some development/construction risk. Development capital offers higher returns but requires investors to take on the risk of site selection, environmental studies, construction permits and grid interconnection.
Second, the revenue mechanism varies significantly across jurisdictions. When it comes to price, most renewables projects of the early vintages had 15- to 25-year fixed subsidies. Over time, as the underlying technologies developed, fixed and indexed feed-in subsidies were gradually replaced by competitive tender mechanisms and the use of market-based solutions such as feed-in premiums and green certificates.
As discussed in our first article, the exposure of renewable developers to merchant power prices has increased, making the revenue streams of some projects less predictable. According to the report by WindEurope/ SwissRe, by 2030 only 6% of European wind capacity—from 75% in 2017, will be fully protected through subsidy schemes. The vast majority of wind projects will operate under mechanisms partially exposed to the market, with up to 10% of new capacity having full merchant exposure.
Insulated from macro factors but watch interest rate risk
In addition to their income potential, investing in onshore wind and solar projects is appealing to investors to lessen portfolio macro sensitivity. In our study (fig. 3), we measure the correlation of total returns for unlisted renewables and regulated network utilities to common macroeconomic factors since 2006, the start of the EDHECinfra Green index. We find that renewables are relatively insulated from the state of the economy and commodity prices. We expect this advantage to remain, given the increasing decoupling of power demand and economic growth. As the energy transition takes off, we will experience rapid power demand with the uptake of electric vehicles and the electrification of industry, where feasible.
Renewables projects based on established technologies and network utilities under supportive regulation can sustain higher leverage than the average infrastructure company. Lenders have become more comfortable and experienced funding renewable energy, on a few occasions even extending facilities to fully merchant renewables projects. The high levels of debt explain the relatively high sensitivity of renewable energy to nominal risk-free interest rates, specifically U.S. and German bond yields.
As central banks raise base rates and corporate credit spreads widen following the global energy crisis and recent banks failures, the capital structure of renewables projects will come into focus. For the global renewables dataset in our study, slightly less than 10% of the debt expires in the next 3 years, and some of it will need to be refinanced at a higher all-in cost. Anecdotally, we see funding costs increase from 2% per annum to 5% per annum, depending on the risk profile of the project.
Renewables projects based on established technologies and network utilities under supportive regulation can sustain higher leverage than the average infrastructure company. Lenders have become more comfortable and experienced funding renewable energy, on a few occasions even extending facilities to fully merchant renewables projects. The high levels of debt explain the relatively high sensitivity of renewable energy to nominal risk-free interest rates, specifically U.S. and German bond yields.
As central banks raise base rates and corporate credit spreads widen following the global energy crisis and recent banks failures, the capital structure of renewables projects will come into focus. For the global renewables dataset in our study, slightly less than 10% of the debt expires in the next 3 years, and some of it will need to be refinanced at a higher all-in cost. Anecdotally, we see funding costs increase from 2% per annum to 5% per annum, depending on the risk profile of the project.
Project economics supported by attractive cost of capital
For early movers in the unlisted renewable energy space a decade or so ago, returns have proved attractive, outperforming other core assets. In later years, however, returns followed a downward path. The three-year annualized returns for EDHEC’s infraGreen index are at 4.5%, compared to 10.1% on a 10-year basis (table 1). There are many factors behind the compression in returns: maturing technology and reducing input costs de-risked projects while accelerating capital flows into clean energy bid the cost of capital lower.
The low point in returns came at a time when projects were more exposed to inherently volatile merchant prices and the queues for grid interconnection lengthened. Robust demand meant that the expected returns from investing in renewables projects were very close to the cost of capital despite a consistent trend of falling financing costs (fig. 4). In Europe, the cost of debt for renewables declined to as low as 1.5% all-in per annum at the end of 2021 from 4%-5% per annum in the early 2010s according to EDHECinfra.
This is slowly changing. The returns for unlisted renewables have started to recover from last year (Table 1) and rising interest rates imply higher expected returns. Developers are benefitting from normalizing supply chains and commodity and power markets calming down. In part accelerated by the U.S. Inflation Reduction Act, developers in the U.S. are reporting plans to expand solar capacity by 43% in 2023, the largest increase in solar capacity since 2016.3 In the future, the economics of renewable energy projects will continue to depend on providing a sufficient spread to the overall cost of capital, while considering the additional operational risks compared to other core assets.
The low point in returns came at a time when projects were more exposed to inherently volatile merchant prices and the queues for grid interconnection lengthened. Robust demand meant that the expected returns from investing in renewables projects were very close to the cost of capital despite a consistent trend of falling financing costs (fig. 4). In Europe, the cost of debt for renewables declined to as low as 1.5% all-in per annum at the end of 2021 from 4%-5% per annum in the early 2010s according to EDHECinfra.
This is slowly changing. The returns for unlisted renewables have started to recover from last year (Table 1) and rising interest rates imply higher expected returns. Developers are benefitting from normalizing supply chains and commodity and power markets calming down. In part accelerated by the U.S. Inflation Reduction Act, developers in the U.S. are reporting plans to expand solar capacity by 43% in 2023, the largest increase in solar capacity since 2016.3 In the future, the economics of renewable energy projects will continue to depend on providing a sufficient spread to the overall cost of capital, while considering the additional operational risks compared to other core assets.
Conclusion
We expect renewables policy momentum to unlock development potential and increase project pipelines by 2030. Operational renewable assets provide many of the characteristics and return expectations that investors are seeking for core infrastructure assets. However, investors should also consider operating risks (demand factors and volatile merchant power prices) and the level of financing costs in analyses. Renewables can lower a portfolio’s macro sensitivity but their exposure to macroeconomic factors is dynamic and needs to be constantly re-evaluated. They will continue to deliver a wide divergence in return and dividend outcomes by project, highlighting the benefit of careful due diligence and return-optimizing investment strategies.
1The value of hedging, new approaches to managing wind energy resource risk. WindEurope, supported by Swiss Re, November 2017.
2IEA, Global EV Outlook 2023
3U.S. Energy Information Administration. February 6, 2023. More than half of new U.S. electric-generation capacity in 2023 will be solar.
1The value of hedging, new approaches to managing wind energy resource risk. WindEurope, supported by Swiss Re, November 2017.
2IEA, Global EV Outlook 2023
3U.S. Energy Information Administration. February 6, 2023. More than half of new U.S. electric-generation capacity in 2023 will be solar.