Developers likely to prioritise CfDs in 2024, while green hydrogen is increasingly featuring in offtake discussions
The possibilities created by higher CfD strike prices in 2024, the impact this could have on corporate PPA activity, and the prospect of hydrogen producers emerging as PPA offtakers were all to the fore as Energy Rev gathered industry players for a briefing session in London on December 7, in partnership with Gowling WLG.
The various established routes-to-market available to renewables generators – as well as some tantalising newer options – dominated the discussion during Energy Rev’s latest briefing event, held in London last week at Gowling WLG’s Thames-side offices.
The topics, namely the UK government’s CfD framework and the corporate PPA market, have been ripe for debate over recent quarters as first volatile electricity prices and then increased capex and capital costs have sent ripples through the industry.
These ructions culminated in both a far from optimal CfD allocation round five (AR5) held earlier this year and efforts by the government to get the programme back on track for future editions, as well as some developers pursuing buoyant PPA values as an attractive alternative.
While offshore wind’s absence for the first time from the last auction round – inadvertently enforced by a too-low bidding cap – stole the headlines and spurred ministers into action, onshore renewables was left to clean up the available budget, but cost pressures still persist for these latter projects.
Panellists at Energy Rev’s briefing event felt that, while AR5 cleared at an attractive price for the winning solar and onshore wind bidders, their proximity to the maximum allowable strike price has compelled caps to be increased for the next auction, potentially creating a new generation of more valuable projects.
However, the nature of a cap naturally does not mean the resulting AR6 tariffs will clear at that level, the panel noted, despite recent experiences in both the UK and across Europe of auctions routinely hitting their maximum allowed prices.
It may even be the case that projects that received CfDs in the 2023 round in the UK have an advantage over the 2024 batch in terms of extra flexibility.
“We’re not going to know the results of AR6 for a while and many things will change: capex, inflation and global factors. Projects are becoming more challenging in the UK in terms of grid and type of land, and the LCOE will see pressure from that,” said Zosia Riesner, director of power markets, Europe, at Lightsource bp.
“The delivery timeframe for AR6 is aligned with AR5, and so the UK gives flexibility around when you hit COD. AR5 projects can wait to see capex come down,” she added.
Nevertheless, the consensus is that winning AR5 bidders are content with their lot, with the GBP 47/MWh solar strike price and GBP 52.29/MWh tariff for onshore wind (both in 2012 prices) expected to perform favourably for contract holders when inflation is accounted for.
While some flexibility remains for the latest CfD winners, the scope for tinkering is being reduced, with the so-called merchant nose – an initial period during which generators can sell at higher wholesale prices before selling at the lower CfD price, and a contender for the renewables phrase of 2022 – now being regulated almost out of existence.
Gowling WLG partner Gus Wood, explained during the panel discussion: “The merchant nose became very attractive because of very high power prices; the ability under CfD to call a start date, you could reach COD and operate outside of CfD and earn what was very high power prices and then fall into CfD when prices were less attractive. Going forward, you can no longer do that as the central counterparty can force you to call COD, so that’s a big change,” he said.
Changing conditions for bidders, both successful and for those missing out, also have implications for the PPA market. Those now armed with higher than expected tariffs, or perhaps also developers expecting to be able to achieve good prices during AR6, may somewhat suppress demand for corporate PPAs.
In effect, the panel agreed, this could result in a wait-and-see approach in the PPA market over the coming year as generators will be reluctant to leave value on the table by signing what may ultimately turn out to be a less lucrative contract with a corporate offtaker than what could be achieved with a 2024 CfD bid.
Furthermore, the past 18 months of electricity price volatility, downgraded long-term forecasts, and uncertainty around when prices may return to normal – and for that matter the nature of what normal actually will look ike – have led to a widening of expectations among both buyers and sellers.
Market fluctuations placed further emphasis on the varying motivations that have always existed among corporate offtakers, with some being more ESG-focused and others placing a greater weight on price factors, although the latter is still an important criteria for all buyers.
And ultimately there is a limit in terms of the prices corporates will sign at, particularly in a falling market. PPA price levels of around GBP 80/MWh for 10-year pay-as-produced deals have regularly been cited in recent months by market sources, but the reality may be that it is a more complex issue to actually achieve a figure near that mark.
“We had so many discussions with generators over the last 18 months who’ve been offered GBP 80/MWh, CPI real, pay-as-produced for 10 years, but those projects still haven’t gone ahead,” said John Puddephatt, PPA origination manager at Statkraft.
“There was a lot of talk about extremely high prices, but we didn’t see many actually materialise. A lot of the projects we spoke to then went on to achieve CfDs,” he added.
With a renewed enthusiasm for potentially higher-value CfDs to come over the early-to-mid-part of 2024, multiple other generators may be prepared to wait for the results of next year’s auction before contemplating entering into a PPA, if at all.
Regardless, the volume of projects coming through to shovel-ready status at present should be sufficient to support increased corporate PPA activity after the AR6 results are in. But, there are also increasingly alternative options that can be taken advantage of.
Panellists highlighted increased activity in the green hydrogen space in recent quarters and this could soon – perhaps quicker than previously expected – become a bona fide alternative to both CfDs and PPAs for a renewables route-to-market.
James Samworth, partner at Schroders Greencoat, noted that green hydrogen producers represented around 25% of the in-bound PPA business his company had been contacted about over the past year, up from next to nothing in previous years. Lightsource bp, meanwhile, could sign its first PPA with a green hydrogen producer in the next 12-18 months, according to Riesner.
Nevertheless, despite the green hydrogen offtake activity seen by Schroders Greencoat, this has to date only resulted in one concluded transaction – for 62.5% of the output from the 288MW Butendiek offshore wind farm in Germany – and several complexities persist which are preventing other deals getting over the line.
In the UK, the government is currently running its first Hydrogen Allocation Round (HAR 1), which will award up to 250MW of electrolyser capacity with bilaterally negotiated tariffs as a means of aiding the development of the sector and ultimately bringing down costs.
Any resulting increased competitiveness should be a boon for renewables generators as, ultimately, for hydrogen to be green it needs to be powered by wind, solar or other clean energy electrons.
The UK government is also planning to ratchet up the competitive tension from 2025 as it moves to a CfD-style bidding model for its HAR framework, which it hopes will help developers find further efficiencies.
Nevertheless, there are some reservations about this timeline.
“It is a long way from the sophistication of the offshore wind, solar or onshore wind supply chain and industries. To think in 2025 we’ll be bidding a fully competitive CfD, that’s quite ambitious,” said Samworth, whose asset management company is backing three green hydrogen projects in HAR 1.
In such an immature part of the market, there will almost certainly be tweaks to the framework and impossible-to-ignore lessons learned along the way, and those involved in the first process are being encouraged to provide comprehensive feedback on its design.
For hydrogen to become a viable alternative for PPA-seeking renewables developers, which granted, is perhaps not its primary purpose but one which could be a reality over the near-term, cost is not the only obstacle as technical challenges also persist.
“Renewables are intermittent, hydrogen customers’ demands mostly aren’t, but they are for a price. So how is that flexibility managed and who can share more risk?” asked Samworth.
“Although hydrogen is expensive to transport, it’s quite easy to store in some quantities for some times, so I feel hydrogen is going to play a bit of a shock absorber role in managing some of that volatility and intermittency, I think that will become increasingly important,” he added.
This latter point speaks to the, perhaps, sometimes understated role hydrogen can play as a long-duration storage technology, which ultimately may comprise a very useful component of hydrogen revenue streams over the long-term, and in effect ease some concerns around relatively high costs of production.