On 2 March 2020, the UK Government issued a consultation on proposed changes to the contracts for difference (CfD) regime of support for renewable electricity generators. The item that attracted most attention was that onshore wind (in GB as a whole, rather than just on Scottish islands) and solar will be allowed to apply for CfDs again in 2021, but there are other points worth noting too. There are proposals to change aspects of the CfD regime relating to offshore wind and biomass conversions, as well as cross-cutting proposals (on areas including negative pricing, non-delivery incentives and “supply chain plans”) that would affect all technologies.
Offshore for net zero
The CfD regime is becoming mature. It was first consulted on in 2010; was legislated for in 2013/2014; saw the first, “FID enabling”, contracts awarded in 2014; and held its first auction in 2015. Already, more than 20 projects with CfDs have been commissioned and are receiving payments under them. They have a combined capacity of more than 4 GW. A further 10 GW is expected to be added by 2026, based on the delivery of projects that were awarded CfDs in the first three auctions. Offshore wind is, increasingly, the dominant technology in the CfD portfolio.
As of June 2019, the UK has a target of net zero emissions by 2050. And before then, the government wants to achieve 30 GW (as per the March 2019 Offshore Wind Sector Deal), or even 40 GW (as per the December 2019 Conservative manifesto) of offshore wind capacity by 2030. The most recent CfD auction saw just under 5.5 GW of offshore capacity awarded CfDs for delivery between 2023 and 2025, but – assuming that this is all delivered – can such levels of activity be sustained? Even if they are, with auctions occurring every two years and projects bidding to deliver in five or six years’ time, it is not certain that the higher of the two 2030 targets would be reached.
Get off the bottom and go with the float
Although the costs of offshore projects have fallen significantly, and it has become feasible to build them much further from the shore than was once the case, there are concerns about whether it will be possible to fulfil the high ambitions for 2030 while relying entirely on monopile, jacket or suction bucket foundations into which the turbine tower is built. These “fixed bottom” arrays cannot readily be deployed in waters more than 60 metres deep. As the industry grows, and occupies more of the available areas of shallower water, the cumulative impact of each new project on e.g. seabird mortality increases, potentially posing more problems under nature conservation legislation. The Crown Estate recently announced a plan-level Habitats Regulations Assessment of its fourth leasing round of sites for offshore wind development, with a view to addressing these issues.
So the government would like to stimulate more rapid adoption of floating offshore wind technology. Just as the construction of North Sea oil rigs progressed from fixed bottom to floating structures, the expectation is that offshore wind can do the same. If it does so successfully, it will become possible to locate turbines over a wider area. This would reduce cumulative adverse environmental impacts and likely increase security of supply (reducing the risk of loss of generation because the wind happens to have slackened or stopped blowing in the areas where turbines are located). The consultation document also suggests that floating turbines could provide clean electricity for offshore oil and gas infrastructure. Moreover, with an eye to export markets, at a global level, the technology will become much more useful in markets such as Japan and California that do not have shallow coastal waters.
Floating wind can of course already apply for a CfD, but in its current state of development, the technology is unlikely to win against fixed bottom and the other technologies that it would compete against in the “Pot 2” category. At present, the CfD regulations do not recognise floating offshore wind as a separate technology. The government proposes to change that, by introducing a new concept of a “floating offshore wind CfD Unit” – defined as consisting entirely of floating turbines. It would then be possible in future auctions to set a framework that effectively reserved part of the budget to such units – or at least ensured that they were not in direct competition with low-cost fixed bottom developments.
In a class of its own?
The government proposes to retain the current 1500 MW cap on phased offshore wind projects, “to strike a balance between economies of scale and facilitating new entrants to the market”. But a final notable proposal in relation to offshore wind is that in future auctions, offshore wind projects might only compete against each other, rather than – as previously – against other “Pot 2” technologies such as advanced conversion technologies, or against “Pot 1” technologies like onshore wind and solar. Whilst it is arguable that offshore wind no longer fits the “less established” designation of Pot 2, the very large scale of the fixed bottom projects now coming forward does make it somewhat mismatched with other technologies. As the consultation document notes, such a restructuring of the Pots would require “regulatory approval”, but there is plenty of precedent for mechanisms designed to offer support specifically to offshore wind projects being approved under the EU state aid rules, and there is unlikely to be any lack of competition for CfDs in an offshore-wind only category.
Meanwhile, back on dry land…
The extent to which the fortunes of the onshore wind industry have been restored by this consultation should not be overstated. Previous governments took more than one decision that curbed its growth. As well as deciding not to include onshore wind in the second and third CfD allocation rounds (unless they were on remote Scottish islands, in the case of the third round), and accelerating the closure of the previous subsidy regime, the Renewables Obligation (RO see here and here), they adopted a planning policy that restricted the pipeline of new consented projects in England. The promise to include onshore wind and solar in the next allocation round, to be held in 2021, does not change that.
However, it is still likely that a significant number of consented sites have been “awaiting construction” primarily because of the lack of RO or CfD support or any adequate substitute for the revenue stability they provide. There should be plenty of competition for the next auction in Pot 1, not least in Scotland, where there is plenty of wind and there has been no Scottish Government policy similarly restricting the pipelines of consented projects since the closure of the RO. The consultation notes that, although there are unsubsidised “merchant” solar and onshore wind projects being constructed, “there is a risk that if we were to rely on merchant deployment of these technologies alone at this point in time, we may not see the rate and scale of new projects needed in the near term to support decarbonisation of the power sector and meet the net zero commitment at low cost”.
The consultation does not suggest how much money might be offered to the part of any future auction in which onshore wind and solar would compete (“Pot 1”). We note, however, that there are some illustrative figures in the accompanying impact assessment (albeit they are expressly “not an indication of future allocation round parameters”) that seem to envisage that in a future round where about the same amount of offshore wind was awarded CfDs as was the case in the third allocation round (5.5 GW, with strike prices of £45/MWh at 2012 prices), 300 and 700 MW of onshore solar and onshore wind might be similarly successful (with strike prices of £33 and £34/MWh). In the first CfD auction in 2015, the largest successful solar project was 19 MW – today, the whole of a hypothetical 300 MW of solar CfD capacity could be swallowed by a single development.
It’s not just about the clean energy
The consultation also focuses on the importance of renewables projects benefiting local communities. It proposes updating existing guidance and creating a register of projects’ community benefits. It also cites some examples of good practice and asks for further ideas in this area. Previously, it has proved difficult, particularly for larger commercial projects, to deliver what might be the most obvious community benefit (cheap, clean, locally-generated power) directly to the communities that host them, because of the way that the GB electricity industry and its licensing and network charging regimes are structured. But it may be that the commoditisation of battery storage could help going forward.
A key element for CfD projects with a capacity of more than 300 MW has been the requirement to submit a “supply chain plan” as part of the application process. The intention has been to ensure that the development of the renewables industry – and the offshore wind sector in particular – delivers some benefit to the UK industrial base. The consultation notes that Ministers can take account of an applicant’s failure to implement a supply chain plan when considering subsequent applications. Potentially, all partners with a 20% or greater share in a project can find themselves excluded from an allocation round as a result. It further notes that the government wants to ensure that the regime contributes to the Grand Challenges of its Industrial Policy and “advances the low carbon economy in places which stand to benefit the most by boosting productivity, driving regional growth”. It is therefore asking how it could strengthen the supply chain policy so as to ensure it remains “fit for purpose”.
Among the possibilities mentioned in the consultation document are: increasing the quality of supply chain plan commitments and closer monitoring of their implementation; extending the requirement to provide a supply chain plan to projects below the current 300MW threshold; and “considering the carbon intensity within supply chains and how this could be measured and/or reported, and taken into account, as we transition to a net zero economy”. The last of these points reflects a familiar tension between free markets / free trade and environmental policy that the EU Green Deal also seeks to address, and that could, potentially, be resolved by a scheme of carbon pricing that incorporated border adjustments on goods imported from countries with less stringent carbon emissions regimes.
After the end of coal-fired power – the end of its afterlife
A significant chunk of current CfD funding (as of RO funding before it) goes to former coal-fired capacity that has been converted to burn biomass. The CfDs awarded to biomass conversion projects have a shorter duration than other renewable CfDs, being scheduled to end in 2027. The government is “reviewing the role of biomass conversions and…seeks views on the proposal to exclude new biomass conversions from future CfD allocation rounds”. The consultation document points out that “since the government’s 2012 Bioenergy Strategy we have been clear that coal-to-biomass conversions have been supported as a transitional, rather than long-term technology” and that those “which are not otherwise subsidised may apply to participate in the Capacity Market”.
What does this mean? At present, there are only five coal-fired plants remaining in operation in the GB market. Of these, Fiddler’s Ferry and Aberthaw B are scheduled to close by the end of March 2020. Drax recently announced that its remaining coal-fired units would not operate beyond 2022. The operators of West Burton B and Ratcliffe have yet to announce plans to close them before the government’s deadline of the end of 2025 for ceasing GB coal-fired generation. That deadline, although confirmed policy, has yet to be specifically enacted as legislation, although limits imposed by EU law on the eligibility of higher emissions fossil fuel plant to participate in capacity markets are expected to make it hard for them to operate economically (a consultation of July 2019 that sought to address the detail of implementing this restriction has yet to see a government response).
Against this background, one can see why it is possible that some remaining or recently closed coal-fired plants might be interested in the prospects of biomass conversion. The attraction of biomass in the earlier phases of promoting renewable electricity generation, and particularly in the form of conversion from coal, was that it could deliver large amounts of renewable power that was not intermittent (like wind and solar) and made use of existing generation and transmission infrastructure. At the same time, there has always been a debate about how truly sustainable the burning of large amounts of solid biomass can be, particularly if it is imported from e.g. the other side of the Atlantic. Then again, if it is accepted that biomass combustion can be carbon neutral, combining it with carbon capture, use and storage (to make so-called BECCS), offers the prospect of “negative emissions”, as part of the drive to offset some of the hard-to-remove emissions that would otherwise stop us meeting the net zero target.
Since the government is considering the CfD as a mechanism for funding CCUS power projects, would it be legitimate to infer that the government does not expect future BECCS projects to be conversions of coal-fired plant? Not necessarily: the CfD legislation currently treats “biomass conversion” and “CCS” (the latter being defined without reference to the fuel that is used to power it) as distinct categories of “eligible generating station”. So it may be that excluding biomass conversions from future auctions would still leave the way open for a BECCS CfD.
Clearing the road to 2030
The government plans to hold the next allocation round in 2021 and to hold subsequent rounds every two years thereafter. In order to further provide long-term certainty to developers investing in bringing forward new projects and to support the level of ambition needed to meet the 2050 net zero target, it proposes to extend the CfD legislation’s definition of “delivery years” to go as far as 31st March 2030.
It’s never too early to think about decommissioning
There are already almost 2,000 offshore wind turbines in the sea around the UK. Decommissioning costs for those in operation or construction in 2017 alone has been estimated at £1.28bn-£3.64bn (in 2017 prices). Against this background the government wants “to ensure developers give appropriate consideration to decommissioning during the development stage”, so as to minimise the risk to taxpayers of the government having to act as decommissioner of last resort, and it is considering “whether it would be appropriate to include specific decommissioning obligations in the CfD regime”.
Administrative strike prices
The government is considering changing the method that it uses to calculate the administrative strike prices that function as “reserve prices” in CfD auctions. The current method produces administrative strike prices that are too far adrift from auction bids for some technologies.
Never mind the carrot, is the stick big enough?
The government is considering sharpening the incentives to deliver CfD projects, and do so on time. It is concerned that as “prices come down and the greater benefit of CfDs shifts from providing subsidy towards offering the support for successful applicants to secure finance for their projects, there may be an increasing risk that a generator does not proceed to deliver on its contract but considers it preferable to deliver on a merchant or other basis”. This, the government says, would be unfair on other generators who might have wanted to make use of the CfD support if they had had the opportunity. It proposes to extend by three years the period during which the site of a project that has allowed its CfD to lapse or had it terminated is “sterilised” for the purposes of a further auction.
Consultees are invited to suggest other potential mechanisms to guard against non-delivery. One model that is mentioned is that of bid bonds such as are used in the Capacity Market (applicants pay an amount based on the project’s capacity, to be forfeited if it is not delivered under the CfD regime).
One of the things that has changed over the last five years is the extent to which increasing amounts of intermittent renewable capacity is driving – and is, in the future, expected to drive – negative pricing in wholesale electricity markets. In 2015, the government thought that this might happen 0.5% of the time in 2035. With 30 GW or more of offshore wind, it now thinks it could happen 4.5% of the time.
As part of its clearance of the CfD regime under the state aid rules, the European Commission required that support should be capped at the level of the strike price in periods of negative pricing, and that if these persist for six hours or more, “the difference amount under the CFD Contract will be set to zero for the entirety of that period”. The government would now like to remove any incentive on CfD generators to generate when there is oversupply in the market. It therefore proposes to “extend the existing negative pricing rule so that difference payments are not paid to CfD generators when the Intermittent Market Reference Price is negative”.
What else is in store?
One of the ways that CfD generators might, at least hypothetically, wish to mitigate the risks associated with periods of negative pricing – and one of the ways in which they might be able to play a part in restricting the incidence of such periods – would be if they could generate, but not immediately export (or be treated as having exported) their power, by making use of storage facilities. Storage is, more generally, as the consultation document acknowledges, “a means to mitigate some of the potential negative impacts of intermittent renewable generation on the system”.
The government therefore asks three quite open-ended questions: “What storage solutions could generators wish to co-locate with CfD projects over the lifetime of the CfD contract? What, if any, barriers are there to co-location of electricity storage with CfD projects? What, if anything, could be changed in the CfD scheme to facilitate the colocation of storage with CfD projects?”.
Co-location of storage with renewables projects already takes place in the GB market. Some large wind projects (onshore and offshore) have relatively small associated small storage facilities. Some smaller projects such as solar farms have proportionately larger amounts of associated battery capacity. Their storage facilities can enable these projects to earn supplementary revenues in the ancillary services markets or the Capacity Market, and help to optimise their assets in other ways.
What is arguably missing are incentives for the development of much larger scale facilities that could be capable of absorbing, for example, a significant proportion of several windy nights’ worth of offshore wind generation for which there is no immediate demand. Also useful, perhaps, would be incentives to develop commercial scale electrolysis facilities into which surplus power could be diverted for conversion into “green” hydrogen that could be substituted for hydrocarbons in power, heat or transport applications. But whether the CfD regime would be a suitable vehicle for such incentives (and, if so how it would need to be adapted to provide them), is another question.
The two most prominent pillars of GB’s early 2010s Electricity Market Reform regime, CfDs and the Capacity Market, are now established features of the landscape. The present CfD consultation, and the recent five year review of the Capacity Market, appear to confirm that no fundamental changes to or replacement of either regime (such as was proposed by Dieter Helm) is planned – although it should be noted that the consultation on effectively replacing CfDs as the subsidy route for new nuclear projects, which would be a significant change to the EMR vision, has yet to be responded to by government (nuclear goes essentially unmentioned in the present consultation document).
At the same time, there is a recognition that – like any element in the complex ecosystem of energy regulation – the performance of the CfD regime needs constant monitoring, and there is a willingness to consider potential improvements. As the regime enters its second decade (counting from the first consultation) or its second five years (counting from the first auction), this is not a bad place to be.