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Glossary · Energy industry & energy transition

Contracts for Difference

Contracts for difference CfD Contract for difference electricity market support scheme strike price Investments

Contracts for Difference, or CfDs for short, are contracts for difference. They compare a contractually agreed price with a market price. For power generation plants, this usually means: the operator sells its electricity on the market as usual. In addition, for each megawatt hour generated or eligible, a comparison is made as to whether a defined reference market price is below or above the agreed contract price. This contract price is called the strike price. If the reference price is below it, the operator receives the difference as a compensation payment. If it is above it, then under a two-way CfD the operator must pay the difference back to the contractual counterparty.

A CfD is therefore not an electricity supply contract in the simple sense. Electricity supply and financial hedging are separated. The plant feeds into the grid and participates in the electricity market. The contract for difference, by contrast, stabilises revenues. What matters is not the quantity of energy generated alone, but the price difference per megawatt hour between the strike price and the reference price, multiplied by the quantity that is taken into account under the contract.

Calculation example: one-way and two-way

The strike price is the price per megawatt hour that the contract ultimately secures for the operator for the quantity of electricity taken into account. It can result from competitive auctions, bilateral negotiations or administrative determination. In the United Kingdom, for example, it is adjusted annually to consumer prices (CPI). However, the strike price does not guarantee that an investment will pay off: generation volume, construction costs and operating costs remain risks for the operator.

A simplified example: a strike price of 70 euros per megawatt hour applies to an offshore wind farm. If the reference price is 50 euros, the operator receives 20 euros per megawatt hour. If it is 100 euros, then under a two-way CfD the operator pays back 30 euros per megawatt hour. Under a one-way model, there is only the top-up when prices are low, but no repayment when prices are high. The figures serve for illustration only and are not real contract values.

Whether a CfD is one-way or two-way strongly shapes its effect. One-way models act like a price floor: operators are hedged against downside risk and keep additional revenues when prices are high. Two-way CfDs stabilise revenues in both directions. This also changes how price risks are distributed among investors, the state and electricity consumers. The United Kingdom provides an example: when wholesale prices rose sharply from 2021 in the course of the gas price crisis, under many contracts generators made repayments to the state-owned contractual counterparty. According to the contract administrator, these reduced costs for suppliers and consumers.

Distinction from market premium, fixed feed-in tariff, PPA and forward market

Under a fixed feed-in tariff, the operator receives a fixed amount for electricity fed in, regardless of the market price. The sliding market premium under the German EEG, by contrast, settles the difference between an applicable value (anzulegender Wert) and a technology-specific market value. Under current law, it works in one direction only: if the market value is above the applicable value, the premium falls away, and there is no repayment. In essence, it therefore corresponds to a one-way CfD. It becomes a two-way CfD only if additional revenues above the applicable value have to be paid back. This is precisely what the planned EEG amendment provides for.

A Power Purchase Agreement (PPA) is an electricity offtake contract between a generator and a buyer, usually with a fixed or indexed price. CfDs and PPAs can be combined: in the United Kingdom, many generators sell their electricity via a PPA and receive the top-up to the strike price via the CfD. The European Commission recommends designing such combinations so that the PPA offtaker is not cross-subsidised and PPA markets are not distorted. In Germany, it is disputed how flexibly operators should be able to switch between PPA and support under the new model.

The CfD also differs from the forward market. Forward products hedge prices for standardised electricity volumes in fixed delivery periods. CfDs for generation plants, by contrast, usually refer to the actual or eligible output of a specific plant and often run for much longer. They are therefore closely linked to project finance and state energy policy.

Why CfDs matter in the power system

Wind farms, solar plants and nuclear power plants cost a lot at the outset but comparatively little during ongoing operation. They have to be financed before revenues flow over many years. For investors, therefore, it is not only the expected average price that counts, but also how uncertain future revenues are. The greater this uncertainty, the higher the risk premiums and cost of capital. A CfD can make financing cheaper because it takes part of the price risk out of the project. The risks do not disappear as a result. They are then borne by those who make compensation payments or receive repayments, such as the state budget or electricity customers via a levy.

The electricity market mainly remunerates megawatt hours generated. It does not guarantee that a plant recoups its investment costs. If the share of a technology with very low marginal costs increases, prices fall precisely in the hours in which this technology generates a lot: for photovoltaics in sunny midday hours, for wind in windy periods. This cannibalisation effect makes investment more difficult if revenues depend entirely on the short-term market price. CfDs can limit this risk, but depending on the reference price only partially.

Reference price, profile risk and distorted incentives

How a CfD works depends strongly on the reference price. Possible options are an hourly spot price, a monthly or annual technology-specific market value, a forward market price or another index. In the United Kingdom, the reference price is determined differently depending on the technology, for baseload plants for example from forward market prices. The more closely the reference price reflects actual generation, the more risk passes to the counterparty. With average prices over longer periods, the operator bears more profile risk. After all, it does not generate at the average price, but at the prices of its generation hours. In return, the incentive to market better than the average is retained.

If payments depend on the quantity actually generated, an operator may also have an incentive to keep producing even at very low or negative electricity prices, because otherwise it would lose the top-up. CfDs must therefore regulate precisely which quantities are remunerated, how negative prices are treated, and whether there is an entitlement in the event of curtailment or grid congestion. Production-independent variants are also under discussion, such as CfDs tied to capacity or to reference plants. They are intended to decouple the payment from actual feed-in behaviour. EU law requires two-way CfDs to preserve the incentives that comparable unsupported plants have, so that supported plants respond in a market-based way.

A CfD does not solve grid issues by itself. A financially hedged wind farm can be built at a location with frequent congestion and then cause costs for redispatch or grid expansion. Whether a plant is sited in a system-serving way or contributes to security of supply is decided in grid planning, location steering, permitting and market design.

Legal framework: EU, United Kingdom and Germany

EU: The electricity market design reform with Regulation (EU) 2024/1747 inserted Article 19d into the Internal Electricity Market Regulation (EU) 2019/943. Under it, direct price support schemes for investments in new generation plants based on certain renewable energy sources and in new nuclear power plants must be designed as two-way CfDs or equivalent schemes with the same effect. The obligation applies from 17 July 2027, and for offshore installations at hybrid interconnectors from 17 July 2029. The forms may vary: according to the Regulation, feed-in-based CfDs with one or more strike prices, price floors, and capacity-based or reference-plant-based CfDs are possible, for example. Member States may pass on revenues from repayments to final customers. The Commission published guidance on design in December 2025. State aid law continues to apply alongside.

United Kingdom: There, CfDs are private-law contracts between low-carbon generators and the state-owned Low Carbon Contracts Company. The strike prices are determined in auction rounds or negotiated bilaterally for individual projects. Payments flow in both directions.

Germany (as of 11 November 2026): For plants in operation, the EEG 2023 with a one-way sliding market premium continues to apply. On 29 July 2026, the Federal Government adopted the draft of an EEG 2027 (Bundestag document 21/7867), which the Bundestag debated in first reading on 24 September 2026. The draft retains the market premium in principle and supplements it with an obligation to repay additional revenues above the applicable value. According to reports, this is to apply to supported plants from around 100 kilowatts, and in principle to awards from bidding rounds from 2027. For older awards and plants commissioned by the end of 2026, the existing model is to continue to apply. According to current trade reports, the Bundestag has not yet passed the law. The Bundesrat and state aid approval by the European Commission are still outstanding. Details may therefore still change.

Misconceptions in the debate

  • "CfDs are simply subsidies." In the end result, this is true as long as payments to operators flow on a permanent basis. However, a CfD is first of all a contract for risk sharing. At high prices, two-way CfDs act like a skimming-off of revenues above the strike price. Whether they place a net burden on or relieve the public sector or consumers depends on price developments, strike price, generation volume and term.

  • "CfDs lower the exchange electricity price." Not directly. The short-term wholesale price continues to be formed by supply, demand, grid constraints and the marginal costs of the price-setting plants. CfD payments flow downstream, via levies, budgets or redistributions. CfDs can above all lower the financing costs of new plants, and they can limit extreme revenues.

  • "CfDs replace market design." No. They hedge investments in certain plants. But they do not clarify what capacity is available during periods of low wind and solar output (Dunkelflauten), how storage and flexible consumers receive incentives, or how grid costs and local congestion are reflected.

Institutional significance

CfDs show that electricity markets consist not only of prices but also of rules that allocate risks. A long-term CfD creates obligations over many years, often 15 years or more. These must be financed, accounted for and politically answered for. Whether payments come from the budget, via a levy on electricity suppliers, via a fund or from repayments in high-price phases is part of the instrument. The design of the tender also shapes the outcome. Overly aggressive bids can result in projects not being built if interest rates or construction costs rise. If too many risks are shifted to operators, bids rise. If too many risks are socialised, distorted incentives threaten.

Used precisely, the term CfD therefore means not only a payment when prices are low, but the entire construction: strike price, reference price, repayment rule, quantity basis, term, indexation and institutional financing. Only this design determines whether a CfD facilitates investment, preserves market signals, limits costs or creates new distortions.

Sources

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Edited by eCMS on 11.11.2026 17:58

© 2026 Erik Schmidt. All rights reserved. Quotations with a link to the source are welcome.