Banking on merchant
Renewable energy is moving beyond a reliance on subsidy, but developers, investors and intermediaries are now grappling with the challenges and risks of unsubsidised projects.
The emergence of unsubsidised renewable energy projects represents a tipping point in the low-carbon transition, as a world of choice, innovation and opportunity opens up for investors, developers and consumers, released from the constraints imposed by policy-makers and dependence on public funds.
The disappearance of government-guaranteed revenue streams, however, is exposing wind and solar projects to new risks, particularly volatile wholesale – or ‘merchant’ – power prices, creating both challenges and opportunities.
Europe has led the way with unsubsidised projects in areas with good renewable resources.
Falling costs have resulted in subsidy-free projects moving forward in the UK and Germany, while – further afield – the disappearance of subsidies in Australia has not deterred developers. Even in China, where government money has created the world’s largest installed base of renewables capacity, unsubsidised projects are under development.
An ‘education process’ is under way to convince institutional investors about the opportunity unsubsidised renewables offer, says Alex Brierley, Co-Head of Energy at Octopus Investments. He explains that “the risk-adjusted returns of some unsubsidised assets in some markets look very attractive – that’s why we’re investing at scale”.
As an example, Brierley says an operational onshore wind or solar project benefiting from a feed-in tariff – or, in the UK, revenues from renewables obligation certificates (ROCs) – delivers gross unlevered returns of 6%–7%. “You need to dig into the sensitivities around specific power forecasts, but, in unsubsidised markets, you’re looking at unlevered returns around 10%,” he adds.
Alternatively, by taking construction risk, de-risking assets by entering into fixed-price power purchase agreements (PPAs), or otherwise hedging the expected revenues and then selling them on, mid-teen returns are possible, he says.
Looking for revenue certainty from the corporate market
For many developers, that de-risking will lean heavily on securing a PPA from a corporate offtaker, which can replicate the sort of revenue certainty offered by government-backed feed-in tariffs or contracts for difference (CfDs). According to Bloomberg New Energy Finance figures, companies globally entered into PPAs totalling 13.4GW of capacity in 2018, up from 6.1GW in 2017.
While corporate demand has been growing, however, it is limited – Bloomberg forecasts similar volumes in 2019 as in 2018 – and the contracts tend to be bespoke, so more time-consuming and costly to negotiate.
Also, given that PPAs for new projects tend to be at least 10 years, with some running for more than 20, they expose both buyer and seller to their counterparty’s credit risk. “The offtaker’s credit rating is crucial” to the volume and tenor of debt a project relying on a corporate PPA can support, Schramm adds, and to the degree of merchant price risk lenders are prepared to accept (assuming, as is sometimes the case, that the corporate PPA does not buy all the project’s output).
Perhaps counterintuitively, however, Schramm says that the longer the PPA the more sensitive the bank is to merchant risk.
A big change for project developers is the need to understand the timing of energy production. In the past, feed-in tariffs tended to be offered on an ‘as produced’ basis, so projects were paid the tariff regardless of when the power was generated. However, corporate buyers tend to want power supply that matches their demand profile.
In European markets, power utilities provide a comparable amount of demand for PPAs as corporates, say analysts. The larger utilities generally benefit from stronger credit ratings, existing generation portfolios that can help diversify risk, and the ability to trade and hedge in the electricity markets.
How new entrants are approaching the market
As well as utilities, other entities with energy-trading capabilities are entering the market, such as oil and gas giants. “Where they are aiming to add value is in their understanding of power markets and trading and pricing ‘peripheral’ risk,” says Louise Shaw, Director, Power & Utilities Corporate Finance, at Ernst & Young LLP in London. Often, they can offer longer term PPAs which offer higher floor prices than those with which traditional utility buyers are comfortable, she adds.
Companies such as French major Total have been investing in a range of power-generating assets, including natural gas plants that offer a market for their hydrocarbons, and renewables projects. In March, Royal Dutch Shell announced its intent to become the world’s largest power generator by the 2030s.
Other energy firms see opportunities in helping renewable energy projects manage merchant risk. For example, Norwegian energy company Statkraft is in discussion with developers in the UK to offer what John Puddephatt, its Head of Long-term PPA Origination, describes as a “long-term route to market” for renewables projects.
How hedging can help
Financial and energy sector intermediaries are stepping into this new landscape, with a range of tools to help developers hedge their exposures.
For example, Neas Energy, the energy-trading subsidiary of Centrica Group, has entered into balancing and hedging contracts for a number of large-scale wind farms, such as the 650MW Markbygden facility in Sweden.
That contract underpinned a 19-year PPA entered into with Norsk Hydro. By committing to supply power to the aluminium producer when the wind farm is not generating, while absorbing any over-production, the hedge allowed the wind farm to, in effect, sell baseload power.
A similar approach is the proxy revenue swap (PRS), a financial contract for difference that assumes a project’s price, volumetric and shape risk, explains Richard Oduntan, CEO of Nephila Capital.
“The lender cares about the project’s revenue, and the PRS proxies it,” Oduntan says, transforming variable revenue streams into predictable ones. The product can help projects raise finance by offering long-term revenue certainty, with Nephila able to write PRS contracts out to 12 years in some markets.
It also allows project operators to enter into corporate PPAs where they guarantee to supply firm power to the offtaker. “The PRS can stand between the project and the offtaker, allowing intermittent-generation technologies to sell baseload power”, says Oduntan.
Looking to the future
Growing sensitivity to market prices will accelerate the trend of project operators seeking to squeeze every last cent of cost efficiency from their projects, including from operations and maintenance (O&M). As engineering consultancy Arup notes, “new types of O&M contract could emerge where service providers take on performance, revenue and market risk in exchange for a revenue-based service guarantee”.
One such operational innovation is the virtual power plant service offered by Statkraft. Without the benefits of subsidies, Puddephatt notes, there will be times when the power price renewable energy plants can earn from the wholesale market drops below their operational expenditure – especially for projects facing relatively high transmission costs.
“We see fast-growing demand for more active asset management to optimise how renewables projects dispatch into power markets,” says Ben Warren, a partner in Ernst & Young LLP’s Power & Utilities team, and RECAI Editor. “Capability and expertise in this area is currently somewhat limited.”
Demand-side response techniques – that allow energy users to reduce their power use in response to high prices or during periods of system stress – could further boost the unsubsidised part of the market, says Brierley, at Octopus. “For corporates that can flex the amount of power they’re using against the power generated by the renewables asset, that gets really interesting.”
Similarly, large-scale battery systems located alongside renewable energy projects can allow operators to extract greater value from electricity markets, by charging up when prices are low and selling when they are high. Operators can also earn revenues by offering grid-balancing services and, potentially, participating in capacity markets, which reward generators by committing to supply power during periods of high demand.
Certainly, the landscape is changing rapidly. “It’s a more diversified market in terms of the counterparties that are investing, and their different risk appetites,” says Piñeiro, at Foresight.
In a fluid environment, there is considerable opportunity – and the potential for investors and incumbents to get it wrong, says Warren. “There are all sorts of opportunities for arbitrage exploitation for developers, and a whole set of new risks investors need to consider and price,” he says. “It begs the question as to what risk-adjusted returns will be demanded, and how long it will take for investors to get it right.”
“All of this will put further pressure on incumbents in the marketplace, and raises further questions over conventional, centralised generation’s longer-term role. This is a real tipping point for the renewables sector,” Warren concludes.