A fixed-price offer, with plenty still to fix

What voluntary wholesale CfDs for RO generators mean for investors and the wider GB power market

What ministers have put on the table

The UK government has announced a new policy direction for existing low-carbon generators: a voluntary offer of "Wholesale Contracts for Difference" (WCfDs) for eligible generators not already on fixed-price CfDs, covering around a third of Britain's power supply.

Generators would exchange their volatile wholesale electricity revenues for a fixed CfD-style wholesale price (and, if they are accredited under the Renewables Obligation (RO), would continue to receive RO support as an additional revenue stream). The aim is not to reduce wholesale price volatility itself, but to reduce consumers’ exposure to it by increasing the volume of generation with contracts that pay consumers back when wholesale reference prices exceed the “fixed” strike price.

The government says it will consult on the measure in due course with an allocation process expected in 2027. It has also said it will offer contracts only where they represent “clear value for money” for consumers. Ministers have also described the pricing as "competitive", but they have not yet published any details about how the competition might work. In this short briefing we focus on some of the considerations for RO generators and policymakers.

The choice facing RO generators

The voluntary WCfDs introduce a new commercial choice for RO generators. They can keep their exposure to volatile captured wholesale prices, or they can move their wholesale revenues onto a fixed-price contract. This is important because it means the key question is how much a generator values wholesale price certainty.

The government’s intention to cover only wholesale price risk through the WCfD arrangement means that RO generators would remain exposed to risks related to future RO payments. These risks can be material and are largely policy-driven, for example related to the value of certificates or the number of certificates awarded per qualifying MWh of output. The recent change to the basis for indexing RO payments from RPI to CPI will only have heightened concerns for RO generators.

If the government were to consider a CfD that also covered RO payments, then there may be potential benefits for consumers (beyond the stated rationale of reducing exposure to price volatility) if generators value the protection provided by a contract more highly than that implicit under the RO, which is backed by regulations that investors may perceive as more exposed to future policy or regulatory change. Bringing RO payments under the WCfD umbrella could also allow the costs of the RO to be spread over a longer period, reducing near term costs.

For now, we consider a WCfD that covers wholesale revenue only. The starting point is that a generator's bid is likely to reflect its minimum acceptable fixed wholesale price, which would be the price at which it is indifferent between keeping volatile future wholesale revenues and accepting a fixed-price contract (or put another way, the price that sets the net present value of revenues under either choice to be equal). In practice, the acceptable fixed price will reflect not only a central view of future power prices, but also the generator's view of a range of different factors, including key contract terms. Key questions bidders are likely to consider are:

What is the value of expected wholesale capture prices (which will vary by technology and location), not just the baseload forward curve?
How would future market revenues be affected by the Electricity Generator Levy (EGL), which the government announced would increase from 45% to 55%? The EGL reduces the value to generators of future upside from high wholesale prices, thereby (other things equal) making a fixed contract more attractive. The risk of future changes to the EGL would remain with generators if they do not take up the WCfD.
How effectively can it capture the reference price in the WCfD contract (including differences in ability to forecast output day ahead, if we assume the same reference price as is used for intermittent plant CfDs)?
What hurdle rate should be used to value the revenues with and without a WCfD, and what is its appetite for risk? The hurdle rate may reduce if the contract reduces exposure to volatile wholesale prices and both the “base” hurdle rate and the extent of any reduction are likely to be different for different parties.
Is bidding for a WCfD feasible given existing routes to market, such as Power Purchase Agreements (PPAs)? If PPA arrangements hinder adoption of a WCfD (e.g. by creating a significant basis risk to the WCfD reference price) can they be renegotiated so that both generator and offtaker can benefit from the new arrangement?
What are the specific contract and allocation terms that will drive value (we discuss some examples below), including important legal provisions or protections (e.g. change of law, transferability on sale)?

Since the answers to many of the questions above will differ by generator, bids are likely to differ materially across owners and assets. Some firms will have a more bullish view of future captured prices; others will place more weight on downside risk, cannibalisation, or future policy intervention.

The product design choices that will shape bids

The terms on offer will be a key determinant of how parties value the contract. Key design considerations include:

Contract length - In principle, if a key objective of the policy is to reduce exposure of customers to volatile electricity prices over the longer-term, then there is a logic for similarly ensuring a long contract, covering the remainder of an asset’s life. Longer contracts should also provide a better hedge and stronger revenue certainty, potentially reducing the price a bidder is willing to accept, though longer durations also remove more option value related to high wholesale prices, and potentially around lifetime decisions.

However, this creates a potential challenge if contracts are being competitively allocated since the remaining life of assets is different, driving differences in bid prices and distorting competition. Potential solutions exist, including the use of maxima and minima, or multi-product auctions that allow the auctioneer to choose between bids for different contract lengths reflecting underlying differences in the products being sold. However, the Capacity Market (CM) offers one precedent where such complex approaches were considered and ultimately rejected.

Treatment of negative prices - Since AR4, the government has tightened the negative pricing rule in CfDs so that difference payments are not paid when the intermittent market reference price is negative in any single hour. If a similar rule were applied to a WCfD, the hedge offered by the contract would not exist in negative price periods, leading to higher bids (other things equal). However, it is worth noting that for RO assets, assuming the WCfD covers wholesale revenues only, a negative price rule on the WCfD element of revenues would not, in itself, prevent RO plant dispatching in negative price periods, as the plant would still receive the RO payment.

Indexation – Existing CfD contracts are CPI-indexed. If a WCfD offered similar CPI protection, this would reduce inflation risk and should lower bids. If indexation is weaker, bids will tend to be higher.

Consideration of life extensions - The consultation will need to be clear on whether the contract runs only for the current asset life or whether it survives a life extension. If a fixed wholesale contract makes life extension more financeable, or if the contract remains in place after extension, this is likely to affect the value that bidders place on having the option to extend the life of a project.

There may also be a risk for generators that the government takes the opportunity to try and address some wider challenges beyond the exposure of customers to wholesale price volatility, such as addressing rising constraint costs through adjusting access rights of WCfD plant during periods of constraint. While this may reduce some constraint costs, it will also make the contracts less attractive to many generators, pushing up bids.

Designing the competition

The government has not yet said how the new contracts will be allocated, but the most obvious benchmark is the existing CfD model. Current CfDs are awarded through sealed bids in competitive, pay-as-clear auctions, and the lowest-price bids succeed (subject to budget, pot, and administrative strike price constraints). If ministers want a familiar and implementable starting point, that is the natural reference case.

We note above the issues around securing efficient competition among plants with different lifetimes. Similar issues apply to differences in bids across technologies and locations (driven by different capture prices). This may point to a need for market segmentation to avoid creation of significant infra-marginal rents, but with implications for the number of participants and competitiveness.

Even if the process is a competitive auction, the government will still need a view on its own consumer break-even price. In other words, what is the maximum fixed price it is willing to offer in return for reducing exposure to gas-linked wholesale prices (also accounting for the impacts of WCfDs on EGL revenue-take)? That could take the form of a reserve price, an administrative ceiling, or an internal value for money benchmark. Ultimately, this may present a challenge if the government and the market fundamentally take a different view on future prices. If the government is more bearish about the prospect of future high price periods than the market, bid prices may be too high to be acceptable for the government.

And while it may not matter to the government (since this policy is principally about weakening the gas-electricity price link for consumers), the most likely outcome in a competitive allocation process is that (all else equal) those projects with the most pessimistic view of future economics (prices, capture rate, taxes etc.) are likely to value the hedge most highly, bid low and win a contract.

Recent AR7 reforms point to a more flexible approach to setting auction demand. A WCfD allocation could therefore be designed either around a fixed volume target, a budget target (that expands volume if clearing prices are lower) or around a more discretionary demand curve that expands if bids come in at prices the government considers good value for consumers.

Effects beyond the auction

The announcement also raises wider market questions beyond the auction itself:

Assuming intermittent WCfDs settle against a day ahead reference price, the contract is production-based and there are no obligations on availability, the incentive on plants to avoid carrying out maintenance in higher priced periods may be diminished, resulting in higher costs for consumers.
Dispatch distortions could increase if the WCfD term extends beyond the end of the RO support period, in particular, if a negative price rule is not applied.
A WCfD could reduce generators’ incentive to hedge further forward, reducing forward liquidity.
There may be implications for the PPA market, with PPAs more focused on route-to-market, balancing and shaping services rather than long-term fixed-price hedging.

Finally, as with any major policy intervention, there are likely to be transition issues for generators with existing hedges and PPAs. Suppliers will also need forward visibility over the likely levy cost implications so that they can continue to sign longer-term contracts without taking on additional risk.

The questions ministers now face

Taken together, the announcement points to a fairly clear set of questions for the consultation:

What exactly is the wholesale price exposure that bidders are being asked to give up, and what reference price will the new contract settle against?
Would there be additional consumer benefits from an alternative product that rolls RO support into the WCfD, rather than leaving RO payments outside the contract?
How much risk protection will the government offer through indexation, contract term and negative price treatment?
How much optionality around life extensions will be preserved?
Will allocation be based on a fixed volume, or will demand flex with the prices bid?
How will the government set its own value for money threshold for accepting bids?
How will the policy manage knock-on effects on dispatch, PPAs, market liquidity and supplier risk?

The core point is that the bid price will not just reflect expectations of future power prices. It will reflect a wider range of considerations including contract design. As discussed above, there are many design and allocation issues to be resolved. The more complete and bankable the hedge offered by the WCfD, the lower bids are likely to be. But the more complete the hedge, and the larger the volumes procured, the more the government will need to think about wider consequences for market efficiency and risk management.