DOI: https://doi.org/10.58248/RR95
The government’s Clean Power 2030 mission involves rapid deployment of clean energy generation across the UK.
Investing into new renewables can be considered high-risk as they face high up-front costs, and their long-term revenues depend on wholesale electricity prices that are often set by the price of gas and influenced by geopolitical events.
Financiers demand higher returns if they bear all the future market risk. The government’s Contracts for Difference (CfDs) scheme aims to reduce this risk by guaranteeing generators a certain price for their energy.
Contracts for Difference can reduce the cost of risk
Less risk and more predictable revenues means developers can raise finance through borrowing (such as buying bonds), which is cheaper than equity (where investors buy shares of the company).
Under the CfD scheme, the government-backed Low Carbon Contracts Company (LCCC) guarantees the generator an agreed price (the ‘strike price’) for its electricity. The generator sells electricity into the market and if the market price is below the strike price the LCCC pays the generator the difference. These contracts are two-way, therefore if the market price is above the strike price, the generator pays the LCCC the difference.
The strike price (the agreed price per megawatt hour (MWh) of delivered electricity) is set in allocation rounds (AR), with AR7 (for offshore wind) and AR7a (for onshore wind and solar PV) held in 2026.
Similar contracts are used elsewhere in the energy industry. For example, electricity suppliers (such as Ovo) often set a fixed price to purchase electricity from a generator (such as EDF) over a short period of time, which reduces exposure to volatile markets.
CfDs offer a fixed price on electricity delivered into the grid rather than over a fixed time period. This distinction matters because weather conditions cannot be predicted with confidence more than a few hours ahead, so committing to supply a fixed amount every hour carries significant risk.
Sometimes a generator has committed to supplying electricity, but the transmission network does not have enough capacity to move that power to where it is needed. When this happens, the generator is instructed to reduce output and is compensated through a constraint payment. This reduces risk further by guaranteeing payment even if the generator is constrained.
Achievements of CfD auction rounds
The first set of CfD strike prices were set by government in 2015 at £195 per MWh for offshore wind and £132 per MWh for onshore wind. Following strike prices were set using auctions. Developers submit sealed bids stating a strike price they require, with contracts awarded to the lowest bidders. Successive auction rounds lowered the offshore wind strike price to £167 per MWh in AR1 (2014/15), and by AR4 (2021/22) to £52 per MWh.
Renewable UK suggest that the commitment to periodic auctions helped develop supply chains that lowered costs and improved technology, while their competitive nature reduced the strike price in later rounds.
In the most recent auction (AR7), offshore wind strike prices rose to £91.20 per MWh. The February 2026 Auction Round 7a cleared at £72.24 per MWh for onshore wind and at £65.23 per MWh for solar photovoltaic systems (PV). Onshore wind is simpler and quicker to build, so it is less prone to the uncertainty of future costs, while PV costs continue to fall worldwide.
What is the impact of CfDs on the price of electricity?
CfDs are two-way, meaning that if electricity is sold in the market above the strike price, the difference is paid back. A previous government scheme, the Renewables Obligation (RO), which existed prior to the 2013 Energy Act, paid the generator the subsidy on top of the market price that the electricity was sold for.
In the RO scheme, eligible non-fossil generators could sell Renewable Obligation Certificates (ROCs) to electricity suppliers to meet an obligation to source a proportion of their sales from renewables. The price that electricity suppliers paid for ROCs was passed on to consumers through their electricity bills.
The RO scheme sped up deployment but at a high cost compared to European schemes. It still operates for some generators but it is closed to new ones.
In total, the CfD, RO and other renewable generation schemes accounted for 46.6% of the UK electricity supply in 2024/25, with the majority (30.2%) coming from RO.
The Office for Budget Responsibility shows that the 2024/25 cost for the RO scheme was £7.8 billion, and for CfDs was £2.3 billion, although their predictions show RO costs decreasing and CfDs increasing to 2030.
In 2025/26, the RO scheme cost £89 per year for a typical household consuming 2,700 kWh. This was around 9.5% of the average electricity bill under the price cap.
In order to reduce energy bills, the government announced in 2025 that it would fund 75% of the domestic share of RO costs through general taxation from April 2026.
In comparison the weighted average strike price of all CfD auctions to date was £84.65 per MWh, with the CfD scheme costing around £39 annually for the average household under the Q2 2026 price cap, which is equal to 4.9% of the electricity bill. Compared to the January 2026 wholesale forward price of electricity of £76.30 per MWh, the Energy and Climate Intelligence Unit (a non-profit organisation) estimate that without CfD contracts for wind, the current wholesale cost of electricity could be around £100 per MWh.
The fixed nature of CfD payments can provide greater stability in times of volatile energy prices. The 2022 energy crisis increased the wholesale price of electricity, leading to generators without fixed CfD payments receiving higher revenues. Estimates suggest that generators receiving RO payments increased their revenue by £7.7 million, an increase of around 100%, while generators with fixed CfD contracts had no real increase as they returned any revenue above the strike price.
The fixed nature of CfDs may offset future electricity price decreases; as the increase in renewable generation lowers wholesale electricity prices by displacing gas, CfDs will still receive their strike price, with the difference coming from energy bills.
Do CfDs contribute to constraint or locational issues?
Depending on where a CfD generator is located, there may be additional locational charges based on electricity transmission infrastructure that could influence CfD strike prices. It may also be less able to deliver electricity to where it is needed, resulting in compensation.
CfDs guarantee revenue for a fixed number of years regardless of location. The firm connection aspect means that the energy system operator, NESO, pays compensation whenever the transmission system is unable to take the power generated, called constraint payments. The cost of these payments is passed on to consumers through their electricity bills.
As new transmission projects are still in development, constraint payments remain high. In 2024, Scottish wind farms were paid for 10 terawatts of curtailed electricity. Total constraint payments, mainly in Scotland, were over £2.5 billion in 2025.
At present, if CfD-based generators are asked to reduce production by the system operator to manage transmission constraints, they can request not just their lost strike price but additional compensation, though this may change with future market reforms.
All generators including renewables pay an annual Transmission Network Use of System (TNUoS) charge, which varies across the country. This is intended to measure the extra cost of delivering power from generators to consumers by overhead lines; the charge might also encourage generators to locate their projects in areas nearer to consumers.
Charges are high where demand is low (such as Argyll, Scotland) and low where demand is higher (such as the Midlands and East Anglia), with the difference between them (in 2024/25) of £23,881 per MW per year (for a wind farm) or £7.96 per MWh.
For example, an Argyll wind farm would (at prices in the 2026 CfD auction) would need to deliver 12% more power than one in East Anglia to earn the same revenue. The industry body Scottish Renewables have expressed concern that uncertainty and increases in future TNUoS charges are increasing risk and raising CfD bid prices (PDF), which in turn increases consumer bills.
The future of CfDs
EU Regulation 2024/1747 and its guidance recommend that renewable support schemes should:
- be two-way
- allow efficient participation in the electricity markets
- not receive support when the market price is negative
UK CfDs meet most of these requirements as they are two-way and allow CfD holders to participate in multiple electricity markets. Until recently CfDs were still paid even if prices became negative. This was modified in 2020 so that payments are not made to CfD generators when the Intermittent Market Reference Price is negative.
In response to high constraint payments being passed down to consumers, the system operator is following European Commission State Aids guidance in proposing no extra compensation above the strike price. This could reduce the cost of constraint payments to CfD generators.
There is potential for TNUoS charge reform as part of the Review of Electricity Market Arrangements, with calls to fix transmission charges to prevent uncertainty from lowering investment. NESO’s strategic plans may also influence constraint and locational considerations in the future.
There are also discussions around the UK rejoining the EU internal electricity market, which would affect renewable generation targets and market interactions.
The government has announced that the next allocation round AR8 will be moved forward to July 2026.
Acknowledgements
Professor David Newbery is Emeritus Professor and Director of the Energy Policy Research Group (EPRG) at the University of Cambridge.
Questions about this briefing should be referred to Dr Matthew Tudball ([email protected]) who acted as parliamentary lead for this work.