Given media comment on the imposition of a revenue cap for low carbon generators instead of migration of existing projects onto a CfD, please find below a blog published by Cornwall Insight three weeks ago. Not only did this note the possibility of the revenue cap being a fall back option for the government to give it leverage and an alternative means to achieve the same end, it also takes a tour through the relative merits of a cap versus a CfD, and highlights some of the complexities that have no doubt been faced in discussions between the government and industry players on the CfD idea in the period to date.
High energy prices have been dominating the news for a number of months now and, even with market falls at the end of last week. A lot of the focus has been on high gas prices but questions continue to be asked, from consumers and policy makers, on why they are inflating the revenues earned by low carbon generators. Never has the merit order been bar room and cafe conversation before!
Now the debate has moved on to whether renewables generators should cede their (perceived) windfalls and, if so, at what level, through what mechanism, and for how long. Various models have been tabled across Europe including windfall taxes, inframarginal revenue caps and even fixing the gas cost for marginal generators. But one idea that has captured the imagination of many industry players in the UK, and latterly also BEIS, is the possible extension of the Contract for Difference (CfD) to existing renewables and nuclear generators.
Whilst this idea is in the limelight today, it is not new. In September 2021, in the early flickers of this crisis, we suggested an extended role of CfDs in giving stakeholders greater certainty in evidently more volatile markets. The most cohesive and well-developed proposal was published in April 2022 by the UK Energy Research Council (UKERC) in a paper titled Can existing renewables and nuclear help keep prices down next winter? This developed the case for a new ‘Pot Zero’ CfD auction for existing low carbon generators that would cap wholesale revenues via a “strike price”. UKERC argued that this would allow consumer bills to be lowered by returning payments through bills at times when wholesale prices were above the strike price.
Figure 1: Potential impacts of introducing Pot Zero
At the beginning of this month, Energy UK publicly indicated its support for UKERC’s plan stating that the proposals could reduce energy bills by between an estimated £10.8-£18bn per annum from next year, equating to a £150-£250 saving for a typical household, in addition to a £6.7-£11.1bn reduction for non-domestic users. Renewable UK also publicly signalled its support in the same week. While exact savings are dependent on a number of variables, and government has not yet formally outlined any plans to introduce a Pot Zero CfD, a new Energy Supply Taskforce has reportedly begun discussions with power producers. However, in the context of the Energy Price Guarantee where bills are capped at £2,500/year for the typical household, the benefit of such an approach now would be to reduce the government and taxpayer costs of subsidising gas and power purchases.
In this Energy Perspective we assess some of the impacts and variables of such a scheme, as well as how it might fit with the wider reform signalled through the Review of Electricity Market Arrangements (REMA).
Remembering that the paper was drafted back in April and the market has moved on since then, UKERC explored the potential cost savings across a number of scenarios. The analysis assumed an auction with clearing prices between £50-100/MWh where between 50% and 100% of Renewable Obligation (RO) accredited wind and solar capacity took part. In addition, other scenarios see the addition of the two Drax biomass units supported by the RO, the Sizewell B nuclear plant, and all other operating nuclear assets. This would see the annual output of generation participating in the scheme range between 30TWh and 121TWh, depending on the scenario. To calculate the cost savings UKERC also made assumptions on the current prices that participating assets would be receiving on the wholesale market and through the RO. Wholesale price assumptions were based on day-ahead prices from N2EX from October 2021 to March 2022, which averaged £201.4/MWh. This equated to an average capture price of £190.0/MWh for wind and solar assets over the period. The addition of the Renewable Obligation Certificate (Roc) price of £52.9/Roc resulted in an average price of £243.0/MWh. Meanwhile, UKERC assumed a capture price of £206.0/MWh for biomass, with these also receiving the full Roc value. The nuclear capture price was calculated as £202.0/MWh, with no additional Roc income. It goes almost without saying that wholesale market prices have surged since then. The average N2EX day-ahead price for April to August 2022 was £201.55/MWh but averaged £282.54 for the month of July.
This commentary underlines two of UKERC’s key assumptions: RO and other low carbon generation is volunteering to take part; and auctions are capable of being effectively used for price setting and competitive price discovery.
Is it a bird, is it a plane?
Challenges to these assumptions have rested on the premise that there are low incentives for existing generators to give up windfalls and enter an auction, particularly in the absence of negative consequences of not participating. On face value these observations have merit but dig a little deeper and a more nuanced picture emerges. While continuing to capture wholesale prices to deliver investment return is high up the priority list for many RO generators, their attention will also be turning to how to extend project life beyond the RO. The RO was launched in 2002, with 20-year subsidies on offer and as such there will be those that will now be seeing the end of support in their future business plans (Figure 2). Will they be thinking about repowering and extension after their support periods end? We would expect the answer to be yes where projects have performed historically. A mass procurement exercise for CfDs that allowed the opportunity for a one-off or limited extension of life or even repowering opportunity to be attained could be too good an opportunity to miss. This is particularly the case, given the alternatives of ageing projects, with high opex, and facing wholesale market volatility. The last few years have been a rollercoaster of complex feedback loops between geopolitical events, black swans and market fundamentals; it was not so long ago during COVID-19 that we were talking about historic lows. Recent experience will make project owners question whether all the talk of two to three years of ultra-high prices will be born out in reality. In a sense, the assumption that generators believe excess profits can and will last, so will refuse to play in a CfD, is too simplistic. It depends on their appetite for risk, and that varies a lot across project owners. In the long term, as gas sets prices in fewer and fewer half hours as this decade ends, price cannibalisation is likely to once again concern project owners. While a CfD does require generators to pay back when wholesale revenues are above the strike price, it also provides protection for when wholesale prices drop below the strike price. The value of the CfD is as much, if not more, about risk management than it is about profit making, particularly for those of a lower risk appetite disposition.
One significant factor also absent in most of the analysis to date is the positive impact holding a CfD has on opening up opportunities to sell or refinance projects. It can create a valuable option for owners to sell projects in receipt of a CfD to capital rich institutional investors who hunger for lower risk and inflation linked returns. Even if strike prices see significant concessions to the prevailing wholesale prices, gaining the option to obtain these benefits will no doubt be attractive to strategic utilities in particular. This could reinforce the trend of recycling money into project development, where bigger returns can be made for risk takers.
Part of the negotiating approach from project owners may also be to seek change in law protection through the CfD contract from REMA and other ongoing industry change programmes. We see this as unlikely to be granted, or necessarily widely sought by all project owners. Governments will want REMA to be conducted with the ability to affect the market in a meaningful way, which would be difficult if a large proportion of the existing fleet were not exposed to its reforms. Similarly, project owners will probably recognise that there is only so far contractual protection can take you for change in law. But will these incentives and the government’s negotiating approach, likened by some in the media to the COVID-19 Vaccine Task Force, prove robust enough to deliver a good deal for the customer, without some compulsion?
Figure 2: Total Capacity of RO projects receiving a subsidy
Again, here the picture is possibly more nuanced than it first seems. With the government seemingly ruling out a windfall tax, some have said this significantly weakens their position. But one of the inducements at the government’s disposal is an inframarginal revenue cap. This would set a cap on revenues for technologies that are not the marginal, price-setting technologies. The government is yet to rule this out as an option, or indeed take any public position on it. But for RO project owners the disadvantage of this is that it comes without the downside protection on offer from a CfD. And for those with a relatively low appetite for risk, this means it will be less attractive. Others may wish to take a risk that a temporary revenue cap this winter, might allow them more upside in subsequent years outside of a CfD. More recently inframarginal caps, including numbers to focus minds, have been tabled by the European Commission, potentially covering wind, solar, biomass, and nuclear technologies. And of course, lingering in the background is also the prospect of a change of UK Government with a General Election scheduled at the last May 2024. Labour has stressed its support for a windfall tax and perhaps we can expect it to push parallels with 1997 when it last won power including a windfall tax commitment, albeit aimed at different energy and utilities businesses.
The plurality of options and impacts of timings of implementation itself offers government some leverage. Aiming for implementation of CfDs this winter creates possible hedging losses for those projects that sold forward at lower prices under PPAs. This won’t be all projects, but enough to be a meaningful factor in the debate. Concerns about facing such losses upon winter 22-23 CfD migration has led to a late public splintering of support for Pot Zero type approaches in the industry. As The Times reported over the weekend it has led to voices in the sector to break cover and call for a one-off windfall tax with an investment allowance instead of a shift to CfDs. Noting this, government may see the chance to induce companies to agree to better terms on CfDs (for the consumer). This could be either by conceding the introduction of the scheme next winter once hedges roll off (when prices are still expected to be high, and thus CfD migration will still have value to consumers) but on the basis that in doing so projects would have to be prepared to agree to lower prices following windfalls this winter. Or it could come through pressing ahead with urgency this winter, offering projects some support to cover hedging losses but meaning much lower strike prices to offset the costs, with the threat of a very tightly calibrated tax (now it can be sold as an “industry alternative” in principle) sitting in the background.
We can be heroes
The example of some now calling for windfall taxes from within the industry illustrate that it is not just government parties who fail to see eye to eye on this issue. It is to be expected that the renewables industry will not have a homogeneous voice given the variety of different business models, project owners, investors and appetites for risk. It is dangerous to generalise, but in the main the larger utilities seem to see benefit in supporting energy policy objectives today to build goodwill with policymakers and procure hedges through CfDs against long-term price risk, even if it means agreeing to what could seem low prices relative to current market conditions. Whereas financial investors may find it harder to sell the same deal to their shareholders. In truth there is much more likely to be a spectrum than a binary division of views, but these denote the two general poles of interest.
In the end, our view remains that the Pot Zero proposal has a number of merits, not least its support by industry trade associations, and through its attempt to consider mechanisms in the short term can meet what are assumed to be the long-term policy aims of the government – allowing efficient use of capital to meet net zero in an affordable way. However, taking this route would – for at least the period of the CfDs – move more of the market into the regulated rather than the market model. From a government perspective it hard to know whether that is good or bad, until we know government’s own long-term view of how these two approaches should be developed cohesively across different parts of the value chain. What we urgently need as a precursor for assessing coherence of this, and REMA, is a strong strategic policy statement form the government on energy. A statement that begins to build the bridge from emergency policy to enduring policy.