The Winds of Change: Option fees for offshore projects

Why were option fees so high? 

In a marked departure from previous leasing rounds, in which TCE had set a fixed price option fee and used competency-scoring methodology to differentiate between bidders, Round 4 awards were made to those bidders (all of whom had already passed the technical and financial requirements at ITT Stage 1) who submitted the highest option fee bid (in £/MW/per annum). Critics of the process – including those developers who had a track record of building out projects in the UK and argued for greater emphasis to be placed on the ability of a bidder to deliver – had warned that this would result in a “bidding free-for-all” with leases going to those with the deepest pockets. 
Many of those critics are now saying “I told you so” - the option fees which were bid are eye-wateringly high. Assuming a final investment decision will be made in four years (it could, of course, be longer), the BP-EnBW consortium would have to pay £1.85 billion in option fees for its two projects before it has made those decisions, in addition to its other development costs.  

How can these numbers be explained? As with everything else, it comes down to a matter of supply and demand. The 8GW awarded is significantly lower than the 32GW secured in the third leasing round held in 2010 and there is no certainty as to when the next leasing round will be (Round 4 was itself delayed on several occasions). On the demand side, there is a wall of money looking to invest in renewables (leading to some claiming that we are seeing the rise of – or are already in – a “renewables bubble”) and there are an ever-increasing number of parties with the risk appetite, financial firepower and expertise to develop out offshore wind farms.  

Most notably, the oil and gas majors – under heightened pressure from consumers, investors and policymakers – have been repositioning themselves as key players in the energy transition and looking to diversify into low carbon power production. These companies, who have traditionally operated in an industry used to taking on high-risk projects with significant up-front investment and are used to forming consortia to share those risks, also have the risk appetite and balance sheet to support high bids for projects which have not been through the HRA process, yet alone the consenting process (which has been far from plain sailing for a number of recent projects).

Higher prices for consumers?

These prices are, of course, a good thing for TCE and, therefore, the HM Treasury and the process run by TCE was also arguably a good thing in terms of policy objectives such as innovation and competition. However, there are concerns that these additional costs will ultimately be borne by the consumers. Whilst some have argued that the auction shows that the majors are willing to “pay to play”, they – and their consortium partners – would not have invested in these projects if they did not expect a return (BP states it is expecting 8-10%) and successful bidders will need in some way to recoup these up-front costs in order to do so. One effect could be that they seek to secure higher prices for the electricity these projects generate and that consumers could ultimately bear the cost of the higher prices. This could risk putting the brakes on, or reversing, the gains achieved in lowering the price of renewable electricity in the past decade. It also potentially risks undermining the UK Government’s promise to maintain market conditions which stimulate cost reductions as set out in the Energy White Paper in December 2020. 

Higher option fees to be off-set by further cost savings?

Developers may well be banking on recovering the higher option fee costs through continuing technology advancement and lower operating costs. Scale will be crucial, and it is unsurprising that five of the six successful bids were for projects at the maximum permitted capacity of 1.5GW. It’s notable that the two successful projects bid by RWE – the only utility to successfully compete with the consortia featuring BP and Total – are on adjacent sites and close to their existing Sofia project. It’s certainly a positive sign that, in the same week of TCE’s Round 4 announcement, Vestas unveiled its 15MW turbine, the largest in the world, which it expects will further reduce the cost of electricity in the sector. 

What about the existing market leaders?

There is no doubt that the diverse expertise, skills and capital brought by oil and gas companies could drive further competition and innovation in the sector. However, concerns have been raised that huge up-front option fees – if these are to become the norm – could effectively push out those developers who have been at the forefront of the innovation and growth of the UK offshore wind market over the past 10 years and force them to further focus their attentions on opportunities in less mature markets. This could include not only smaller developers but also others who have to-date been the ‘majors’ of offshore wind in the UK with potentially detrimental effect as we need a broad coalition of expertise to face the significant challenge of rapidly building out capacity to meet a 40GW goal by 2030, particularly as projects will inevitably face more difficult issues with the consenting process, grid connections and transmission system upgrades, environmental concerns and site congestion.

Will this be a feature of future auctions?

It is unclear at this stage when TCE will engage with the industry with respect to the design for Round 5. Whether such high prices will in fact be seen again will depend on TCE’s appetite to further refine (or reverse) the auction design. This option fee structure is the only one of its kind in Europe. As shown by the Round 4 bids, the model has the potential to bring in significant revenue. Yet, it also has the potential to result in higher prices for consumers and risk smaller developers and certain utilities looking to other markets, such as in Japan and the US, with opportunities for good returns and lower up-front costs.  

The results have already had an impact on other auction processes. Shortly after they were published, Crown Estate Scotland announced that it was pausing its (already long-delayed) ScotWind seabed leasing auction in order to review its proposed fixed option prices structure, evidently due to concerns that they were failing to maximise value in light of the option fees bid south of the border. Following its review, whilst deciding to retain its fixed option fee structure, Crown Estate Scotland unsurprisingly sought to increase the Scottish Government’s return, increasing the maximum option fee payable tenfold, from £10,000 per km² to £100,000 per km². All eyes now turn to the results of that auction process, due to be published later this summer.