Our most recent Market Share: A Survey of the Renewables Market Power Purchase Agreements (PPAs) shows that around 25GW of renewables projects access the wholesale market via an offtaker. An additional 5GW of flexible assets (i.e. gas and diesel peakers and storage) are likely operating under PPAs too, which is a view we’ll firm up in the coming weeks.
The wide-spread closure of subsidy schemes, uncertainty of the long-term outlook for the Capacity Market, and steady erosion of embedded benefits has seen the renewables market having to innovate and look to establish ‘subsidy-free’ PPAs. These mostly take the form of either Corporate PPAs or more typically Utility PPAs. Both are used as a means to underwrite investment in new developments, or – as we increasingly expect to be a feature in the coming decade – will be used to support investment in repowering of ageing existing sites.
Currently, even though technology costs are falling, the bankability and economic viability of subsidy-free PPAs hinges heavily on an offtaker’s long-term projections of wholesale prices. In a utility PPA this will drive where an offtaker will set long term floor prices, and in a Corporate PPA this will have a distinct influence on the value and period of price fixing they are prepared to entertain. These are vital variables for developers and their investors. Either a decent, long term price floor or a price fix are still important components of putting together a bankable project, allowing debt providers to lend money with confidence, increasing returns to equity in the process and insulating debt repayments and equity returns from the negative influence of power price volatility or reductions.
In a world of buoyant expectations of future power prices, at the point of setting commercial terms the offtaker’s resulting PPA price fix or a floor may be enough to generate a decent return for investors. But in a world of less optimistic expectations then the opposite will be true, meaning projects risk becoming unviable unless of course capex and opex cost reductions are enough to off-set the impact on returns of lower PPA pricing.
Of course, the commodity element of PPAs has always been important, but in days of subsidy it would perhaps represent only half of all revenue. As a result, when power prices were volatile, or even predicted to fall over the long term, the impact was buffered by other more stable revenues that also acted as an implied price floor within the contract. The Renewables Obligation, and funding structures that emerged around it, classically exemplify this phenomenon.
In a subsidy free world, this buffering is absent. Our new service, the GB Benchmark Power Curve, provides a 20-year view of future generation-weighted power prices under several scenarios and for different technologies. The graph shows power price shape under our Community Renewables scenario (which sees rising demand due to heat and transport electrification and high commodity costs), captured by onshore wind out to 2039. Our assessment today suggests that captured prices for onshore wind until the mid-2030s are generally lower than wholesale prices observed today. This is not necessarily an issue for all projects, as whether this drives viability depends on full financial modelling on a site by site basis, including consideration of volume production, project costs and other revenue sources.
In addition, power price forecasting is a dynamic not static exercise. As assumptions and input data changes, so will the forecasts. Offtakers will not be bound to follow our view and will instead be driven by their own evaluation of future prices. At certain times, and for different offtakers, the PPA terms offered in the market, and which result from the view being taken of future power prices, will likely drive a large volume of project deployment, at others it could drive a drought.
At the same time, the scale of new generation required to meet a net zero emissions position by 2050 is staggering. The Committee on Climate Change, for example, suggests that 150GW may be needed to meet peak demand periods by the middle of this century. Total installed capacity is around 95GW today, and almost all of that will need to be replaced or repowered before this date. As a crude metric this implies an average of around 3GW of new capacity being commissioned annually.
Policy support will persist under the Contracts for Difference (CfD) scheme, and this could bring forward much of the hoped for 30GW of new offshore capacity by 2030. However, there remains a hole in how the lion’s share of new and required capacity will be developed.
Subsidy-free PPAs will play a role, and current conditions show that investment is possible. But, without innovation, this could rapidly change if commodity market conditions change dramatically. This gets to the heart of a challenge for the sector—an investable and economically viable subsidy-free onshore renewable market risks becoming a hostage to long-term and ever-changing expectations of future power prices.
For policy makers the question must be whether this kind of commodity driven investment famine or feast is the basis on which further deep decarbonisation of the power sector can really be delivered? For the market, the question must be how PPAs can be innovated to deliver as much value from a range of system, policy and market sources to reduce sensitivity to movements in power prices alone.
Our one-day PPA – Structures, terms and bankability course on 3 July will explore these issues further. Find out more here.