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The pros and cons of contracts for difference

CfDs have proved effective in incentivising renewables investment and providing price certainty during the energy crisis. But how they move risk and cost around the system could hinder the net-zero transition.

Contracts for difference (CfDs) have become the policy tool of choice for incentivising the deployment of renewables in Europe. They offer generators a guaranteed level of revenue, reducing their risk. In exchange, they involve payments from generators to government if power prices rise above that strike price, reducing their cost. And they tend to be offered through competitive auctions, helping to drive down the price at which they are struck.

In the UK, CfDs already auctioned by the government will, by 2030, cover some 30GW of renewable energy generating capacity in the UK, mostly offshore wind. The government plans to conduct auctions on a twice-yearly basis to contract additional capacity as part of its goal to reach 80% wind and solar energy by 2035.

The exact contribution that the CfD mechanism will make to these targets is currently unclear: it will depend on the degree to which capacity can be built without recourse to government support. However, as we have seen, it appears likely that considerably more CfDs will need to be struck for the UK to meet its climate goals – implying a significant transfer of risk in ways that could undermine the efficiency of the system.

How CfDs work

CfD contracts do not involve the actual sale of physical electrical output, which the generators themselves still need to arrange. They are purely financial instruments which provide cashflows between the government-owned Low Carbon Contracts Company (LCCC) and the generator aimed at providing predictable revenue per unit of power generated.

To date, CfDs have been offered to generators based on the results of four competitive auction rounds (AR1 to AR4). These involve generators competing for the strike price they are prepared to accept. The Initial Strike Price in the auctions is quoted in ‘2012 money’, but the contract is then indexed in line with the Producer Price Index (PPI) to take inflation into account, to form the Adjusted Strike Price for each contract year.

Once in operation, a cashflow takes place each month between the generator and the LCCC equal to the output generated times the difference between the Adjusted Strike Price and the Reference Price – which tracks wholesale power prices – for each hour during the month. (CfD Payment = (ASP – RP) x Output).

There are two types of CfD contacts, Baseload and Intermittent. These are offered respectively to ‘reliable’ generators (such as those using biomass, geothermal or nuclear technology) and ‘intermittent’ generators (using solar PV, wind or tidal assets).

The main difference between the two types of contract is the calculation of the Reference Price.

For Baseload CfDs, the Reference Price is set six-monthly: it is the market price for the forward six-monthly season baseload contract, as quoted during the sixth month prior to delivery. For example, the Reference price for all delivery periods from 1st April to 30th September 2023 inclusive is the forward market price for Summer 23 baseload, averaged over all working days between 1st October 2022 and 31st March 2022.

For Intermittent CfDs, the Reference Price is set hourly: it is the weighted average of the settlement prices for the two day-ahead auctions, run by the N2EX and EPEX power exchanges, for the relevant hour.

A growing risk

The number and size of active CfDs is increasing, and the proportion of national energy demand covered by CfD-supported production is set to grow – particularly when the Hinkley C nuclear power plant comes online, which is currently expected in 2027. At present, around 10% of national demand is covered by CfD-supported generation. This figure is likely to grow steadily to 50% or more, dependent on government choices for a net-zero grid.

One additional feature of the CfD regime is that generators have some optionality on when to activate or ‘trigger’ their CfD; and a low penalty if they decide never to do so. Moray East and Triton Knoll are examples of wind farms that are active and could trigger their CfD but have elected not so far. Eventually they will reach a ‘long stop date’ at which point they must either trigger or lose the CfD contract.

Generator CfD hedging

CfDs are designed to allow generators to recover net revenue equal to the Adjusted Strike Price for all their output. They do this by selling their actual output in a way which mimics the calculation of the Reference Price as closely as possible.

Intermittent generators forecast their output for each hour at the day-ahead stage and aim to sell that amount of energy into the day ahead auctions. As long as they have forecasted output correctly (and sold in each of the two auctions – N2EX and EPEX auctions are at different times – in the correct proportion) they will collect from the sale of their power an average price equal to the Reference Price for that hour: Physical sale revenue = RF x Output.

Adding the CfD payment/receipt makes the overall net revenue equal to the generator’s output times the Adjusted Strike Price: (RF x Output) + (ASP – RP) x Output = ASP x Output.

In this situation, the generator will be left with a very predictable de-risked revenue stream, which is affected primarily by the inflationary indexation of the strike price, and by volume risk related to the variability of weather.

In entering into CfDs, consumers – via the LCCC – have absorbed the two main market risks faced by generators, namely wholesale price risk and capture risk. Capture risk is particularly acute for renewable energy generators, which are exposed to structurally lower prices if large volumes of new, low-cost wind or solar generator comes on stream. The LCCC, meanwhile, hedges this risk via the CfD levy – a premium charged by suppliers on all consumer bills, including those of industrial and corporate buyers – effectively ‘socialising’ this cost.

The other markets risks that remain with the generator are the balancing risk and the regime around “Negative Price Periods” (NPPs). During NPPs, no payment is due from the LCCC to generators. For CfDs struck in the first three auction rounds, NPPs are deemed only to occur when the Reference Price is negative for six consecutive hours. From AR4, the definition reduces to any single hour with a negative Reference Price.

(In this blog we don’t consider hedging by generators for baseload CfDs. For biomass CfDs specifically, the instrument has proved ineffective and caused unintended consequences in extreme circumstances. As an example, Drax Unit 1 was barely operational during the winter of 2022/23 despite the highest wholesale power prices of any winter to date.)

Supplier CfD Levy Hedging

Although the LCCC doesn’t purchase physical energy itself, the net financial effect of the CfD regime is very much the same as if the LCCC has made long-term purchases of energy at fixed prices, indexed to inflation, on behalf of consumers and their suppliers. Effectively, it uses the ‘balance sheets’ of all UK householders and businesses to hedge its risk.

The suppliers, meanwhile, are left with weather risk exposures – that wind speeds will be below their historic lows – and that increasing amounts of renewables will cannibalise themselves – capture risk. This is the risk that, as a growing proportion of renewables enters the system, the percentage of the average wholesale price intermittent generators are able to capture over time falls. This is because high wind (or solar) availability pushes down prices, while low wind (or solar) availability pushes prices up exactly when wind (or solar) generators are unable to benefit.

As the CfD effectively passes on these risks to consumers via their suppliers and because the suppliers are not easily able to hedge these risks, and often lack the balance sheets to absorb them, they will want, over time, a higher risk premium on their tariffs. It is worth exploring how suppliers pass on that levy to consumers, and what this will mean ultimately for the overall cost to the system.

Calculating the CfD levy

The CfD Levy paid by a supplier depends on its share of eligible demand, and the payments (or receipts) to CfD generators, on that day. This, in turn, depends on the volumes generated and the difference between the Strike Prices and the Reference Prices for that day.

Suppose for example on a particular day that:

  • Eligible demand is 1,000GWh
  • CfD intermittent generation is 100GWh
  • The weighted average Strike Price is £175/MWh
  • The weighted average Reference Price is £125/MWh
  • Supplier X has eligible demand of 50GWh

Then for that day Supplier X must pay into the CfD levy an amount equal to:
50GWh/1000GWh x (£175/MWh-£125MWh) x 100GWh = £250,000 (or £5/MWh of demand).

In the example above, however, if prices had increased so that the weighted average Reference Price was £175/MWh, then no CfD payment would have been made to generators, and no levy would have been due from the Supplier.

Conversely, if prices had fallen so that the weighted average Reference Price was only £100/MWh, the Supplier’s CfD levy payment would have increased to £375,500 (or £7.50/MWh of demand).

Alternatively, if prices and demands were as set out above, but it was a less windy day and CfD Intermittent Generation was only 50GWh, then the Levy payment due from the supplier would only have been £125,000 (or £2.50/MWh of demand).

In general, only very sophisticated customers have a “pass through” of CfD Levy in their supply contracts. So, for the most part, once a Supplier has agreed a fixed price to supply a customer, the CfD levy risk passes to the Supplier.

Suppliers (and sophisticated customers with pass-through contracts) are then left in the position where – in effect, financially – a part of their demand is hedged by something akin to an intermittent power purchase agreement (PPA) at an inflation-linked price.

Suppliers deal with this risk in different ways; but most allow for some risk when pricing customers tariffs and mitigate this risk by retaining a short position until the day-ahead auction to offset the likely impact of a movement in wholesale prices on CfD Levy rates.

In the example above, if the generation and demand levels were typical of what was expected at the time of year, the Supplier might conclude that it should leave 10% of its expected demand – or 5GWh – unhedged until the day-ahead auction, because 10% of national eligible demand is expected to be covered by intermittent CfD generation (100GWh vs. 1,000GWh).

As long as the volume of generation is as expected, then if prices rise the additional cost of purchasing the remaining energy requirement will be matched by a reduction in the CfD levy cost. Conversely, if prices fall, the saving made on purchasing energy in the day-ahead auction will be offset by a reduction in the CfD levy.

So, in the example above, suppose wholesale prices at the time of customer quotation averaged £150/MWh, but the day ahead Reference Price was only £100/MWh.

  • In customer quotations, the Supplier would have allowed £150/MWh wholesale costs, plus a levy payment allowance – which could have been equal to 10% x (£175-£150) = £2.50/MWh plus a risk premium, perhaps £3/MWh in total – giving a total energy plus CfD levy revenue price of £153/MWh.
  • The Supplier might hedge 90% of its demand at £150/MWh, and then purchase the remaining 10% at approximately £100/MWh in the day ahead auction, giving a weighted average energy cost of £145/MWh.
  • Assuming generation levels as expected, the CfD Levy would be 10% x (£175 – £100) = £7.50/MWh.
  • Therefore, total wholesale energy plus CfD costs to supply would be £152.50/MWh – very close to what was anticipated.

The risk retained

This example shows the high-level principle of how the Supplier might mitigate risks.

However, exactly as if they had bought a fixed price PPA, the Supplier is left holding a large amount of complex ‘basis’ risk related to intermittency.

If the average strike price is above typical market prices on windy days, then the Supplier will benefit if it is not windy. Conversely if the strike price is below the typical market price on windy days, the supplier will benefit if is windy. This dynamic is made more complex because there is a growing relationship between wind levels and day-ahead pricing, as more wind farms are installed.

This complex interaction between price and weather (and hence volume) is called ‘quanto risk’, and it is essentially unhedgeable. It means that even if the Supplier retains a short position to the day-ahead stage, as illustrated above, the risk related to CfD levy is reduced but not eliminated.

Other risks carried by suppliers related to intermittent CfDs include the uncertainty on when and if wind farm CfDs are triggered. At present several AR2 CfDs have not been triggered by the generators even though they are complete and operational, as they receive better revenue in the open market; they may not trigger them even at the long stop date, as the non-delivery penalties are low. This contractual “flaw” in the CfD allows generators to game the mechanism and means suppliers have another unknown variable to factor into their risk calculations. The government is currently consulting on whether to change the trigger arrangements in AR5 to increase the likelihood of contracts being triggered at an early stage.

(In this blog we don’t consider Supplier hedging for baseload CfDs. As we noted above, the instrument has proved ineffective for biomass and caused unintended consequences in extreme circumstances; Drax Unit 1 has barely run during the winter of 2022/23 despite the highest wholesale out-turn prices of any winter so far. The baseload CfD for Hinkley C is likely to prove more amenable once triggered, but suppliers and consumer are carrying uncertainty on the timing of project delivery, which will make initial hedging difficult.)

CfDs and the 2022 energy crisis

In 2022, gas and electricity prices spiked to unprecedented levels and experienced huge volatility in response to the Russian invasion of Ukraine, and the loss to Europe (and the world) of c. 350 million m3/day of Russian gas exports.

Across Europe, national governments felt obliged to protect domestic and business users from the high prices; and also place windfall taxes on domestic producers of primary energy to pay for it.

In this environment, it has been seen as desirable that the government should act to create price stability for consumers, and limit excess profit for primary energy producers. The renewable CfD is an instrument that does both, in addition to its original purpose of supporting new generation and supply chains.

The UK government and the EU considered widening the scope and purpose of CfD instruments to achieve the new aims – for example in the UK by switching RO support on existing schemes to a CfD; and offering “follow on” CfDs to “post-support period” assets.

On the one hand, this does create some price stability for consumers, and limit the potential for excess profits. On the other hand, it is a government intervention in what has previously been a free market and imposes long-term hedges on consumers that they may not want.

What this all means

CfDs have proved extremely effective in incentivising new renewables and, more recently, in helping to manage the impacts of the energy risk. However, the way they are structured in the UK leaves suppliers – and large consumers with pass through contracts – with considerable amounts of weather and quanto risk that is extremely difficult to quantify and hedge. The suppliers only response must be to increase the prices they charge their customers, making the system and the net-zero transition more expensive than it otherwise could be. Generators on the other hand face both balancing and NPP risks that are also very complex and difficult to manage.

As the volume of generation under CfDs increases these quanto risks will only get larger as we will discuss in a future blog.