The STA issued an updated cost assessment of PV on Tuesday 11 December and also called on BEIS to introduce a technology-neutral floor-price Contract for Difference to help renewables investment come forward in a subsidy free environment. The CfD floor price structure is a proposal we developed in early summer, and we are glad to see ideas that we have developed and championed in Cornwall Insight being adopted by the industry. Below is the Energy Spectrum Perspective from edition 623 where we set out our ideas for a CfD Floor price.
Safety net: the case for a CfD floor price
If recent industry comment is to be believed, we are on the cusp of a new, “subsidy-free” era for renewable generation projects, particularly for mature technologies like onshore wind and solar PV. However, we would counter that, as captured prices for renewable projects fall, intermittent renewable projects are unlikely to be built at scale without material de-risking of volatile wholesale power prices for investors. In this week’s Energy Perspective, we consider how wholesale “revenue stabilisation” will be necessary. To balance this against managing consumer costs, reform of the Contracts for Difference (CfD) regime is likely to be required. In our view, a powerful investor stimulus, which minimises the risk of additional levy funding, could be provided via a new “floor price CfD” model.
A large share of investment in the existing renewables fleet in Europe has come from non or limited recourse project finance debt (Figure 1).
Non-recourse debt is so named because the repayment is ring-fenced from the cashflows being generated by the energy project. It has been widely used in the GB market under the Renewables Obligation (RO), small-scale Feed-in Tariff (ssFiT), and CfD schemes. Equity investors have typically been able to raise over 70% of the total build costs from relatively cheap project finance loans. This in turn has allowed developers to spread equity across many different projects at reasonably attractive rates of return.
Providers of non-recourse debt need predictable cashflow over the entire loan. They receive fixed interest and capital repayments, but they get no upside for out-performance of the project, and so prioritise getting fully repaid. This shapes their risk appetite. They are also interested in their loan being reduced through regular, loan repayments. A missed debt repayment period constitutes an impaired loan, which banks must then support through very costly reserving of additional capital. So, if wholesale prices crash in the near term – and even if average prices are adequate over the life of a loan – the banks face real problems.
Against the background of this traditional financing model, power price volatility is already increasing (Figure 2).
Further, there is already a growing discount of generation weighted (or captured) price of wind and solar relative to average power prices as more capacity commissions, which we recently demonstrated in our recent Wholesale Power Price Cannibalisation insight paper (see Figure 3).
Given the requirements of project finance banks, and the increasing backdrop of price volatility, banks will always tend towards wanting wholesale price exposure to be materially de-risked. We have evidence of this in the few “subsidy-free” deals done to date. For example, in the case of the recent financing of the 8.2MW Withernick II windfarm developed by Energiekontor, de-risking came through a corporate PPA. Further support came as this project was an extension to an existing RO windfarm.
Through our consulting work we are aware of corporate PPA contract structures emerging in this market, from initial fixes, transitioning to floor prices, and market index-tracking subject to fees. The prices on offer appear adequate. But to date very few contracts have been written outside of an RO environment. Therefore, it is unclear whether the corporate PPA pricing will really be investable in a pure subsidy-free project. Liquidity in this market is also unproven. The corporate buyers are likely to look for scale and shape rather than multiple small projects. Equally, project finance banks will still need to be confident that the financial capability of the corporate offtaker is sufficient to stand behind a long-term offtake agreement. After these two filters are applied, the community of “bankable” and willing offtakers is unlikely to be large.
If corporate PPAs are only selectively used, then some other model will need to fill the gap. Usually this would imply a role for the state. But the complication here is that, to the extent this is through a government levy-funded scheme, there are constraints around adding levy costs in the period to 2025 under the new low-carbon accounting levy control framework, which we have written about previously in our Static Electricity: New Controls for Low Carbon Levies paper. There is also the political bind of previous Conservative manifesto commitments to prevent new onshore wind from being built.
Both are surmountable. On the former, the new rules will permit support so long as it can be shown it will not add to the levy bill before 2025. On the latter, we have seen a softening of tone by ministers in relation to onshore wind coming into CfD auctions, particularly if capacity can be in Scotland.
The simplest model would simply involve opening up another established CfD auction, with BEIS capping administered strike prices (ASPs) for wind and solar at levels they felt confident would not necessitate new levy costs. To avoid adding to the levy bill, BEIS would need to assure themselves and HM Treasury that ASPs used to cap auction bids were below the government’s own curve of wholesale power prices. These were last published at the end of 2017.
BEIS could take a “whole-life” CfD view, assessing the net subsidy position at the end of the 15-year period at their ASP caps. In which case, in 2017 values, the strike price would be £57/MWh. If they were prescriptively attempting to eradicate any levy payment in all periods, the ASP would be £43/MWh in 2017 values. The latter level would block out all but the most efficient projects, most of which one would expect to be located in Scotland.
But this approach does not leave much margin for error in wholesale power price forecasting. Allied to inaccuracies in load factor estimation, relying on this approach to ensure no new levy may therefore be a difficult ask for the government.
An alternative model could be a “floor price” CfD. Under this model, CfDs would be auctioned in the same fashion as today. But, applicants would bid in the floor price, rather than fixed price payment they require to make the project investable.
In a floor price CfD, if wholesale power prices are below the floor price then levy funded payments would be made to the recipient (Figure 4). However, as wholesale power prices climb above the floor again, the recipient would not receive the positive difference until the gross value of payments received under the CfD had been reimbursed to the Low Carbon Contracts Company. Thereafter, upside would be realisable.
Because of the ability to realise upside, investors are likely to require a lower floor price than the fixed strike prices they currently bid into CfD auctions. Under a floor price CfD, investors are likely to view the floor level as the means to raise their target level of project finance debt.
BEIS could model its own view of an administered floor price (AFP) for onshore wind and solar ahead of auctions, using the AFP to cap floor price bids as they do with current ASPs.
Levies would therefore provide working capital support to stabilise revenues, but only until costs were paid back. The recipient of the CfD would enjoy the upside of the wholesale price, above the level of the floor, for as long as that is sustained. In simple terms, investors would get to ride some upside with a safety net capable of raising debt, while consumers remain protected against rising levy costs in a rebate-style model.
Under this model, it would only be if outturn wholesale power prices were drastically below the floor price for most of the 15-year CfD period that any serious risk of unrebated consumer costs would arise. This is unlikely.
A BEIS senior official recently confirmed there would be no changes to the CfD rules ahead of the next CfD auction earmarked for Spring 2019. But with a longer-term review of the Energy Market Reform framework commencing this summer, there will be opportunity for the case for reform to be made by industry.
We need to set aside the alarmingly optimistic predictions of subsidy-free capacity that are coming forward. They do not appear to be grounded in the realities of how projects get financed and could talk government out of action.
Some interest groups in the market have argued fervently for revenue stabilisation through a CfD auction for onshore renewables using the established structure. But we suspect this will not equip government with the confidence that consumer cost and political barriers can be overcome.
While our floor price CfD model requires further development, it could offer what we hope is a credible alternative that can change the dynamics of this debate.
These ideas were discussed further with industry on 17 October ‘Into the unknown: evaluating drivers of low-carbon investment in a subsidy free world event’. The presentations can be downloaded here.