Fighting global warming requires huge investments in decarbonated energy generation. To address this challenge, the European authorities introduced a regulation promoting the use of long-term contracts. This column argues that while well-designed long-term contracts are good instruments for attracting investment in new generations, preserving the price signal in the wholesale market for efficient dispatching, and sharing macroeconomic risks, public authorities should be cautious not to impose distortionary templates on contracts.
Fighting global warming requires huge investments in decarbonated energy generation. To address this challenge, the European authorities introduced Regulation 2024/1747 promoting the use of long-term contracts. In a recent CEPR Policy Insight (Ambec et al. 2025), we discuss whether these long-term contracts are likely to achieve their two goals: optimal dispatching of existing generation and investment in new generations to reach the EU’s decarbonisation targets.
The need to protect economic agents against long-term price uncertainty rationalises long-term insurance contracts. First, to stabilise their balance sheets, buyers and sellers of electricity can agree on a price and a quantity of electricity delivery in advance. In such a ‘physical contract’, also called a ‘power purchase agreement’ (PPA), the volume specified is effectively injected into and withdrawn from the power grid, requiring guaranteed access to the grid between the points of withdrawal by the buyer and injection by the seller. Electricity consumers and retailers thereby secure their energy sourcing, and power producers can obtain financing for their investments. Contract sales limit market power, if any. While withdrawing electricity capacity from the spot wholesale market raises prices, particularly in times of shortage when supply response is weak, the incentive to do so is lower when a large share of production has already been sold at a given price. It is therefore less profitable for a dominant electricity producer.
The EU Regulation calls for the development of ‘transparent’ markets for PPAs. Transparency requires standardised templates that may leave insufficient flexibility in contract design: electricity-intensive companies and producers may be prevented from negotiating bespoke contracts that are specific to their needs.
Second, the EU Regulation promotes the development of another form of long-term contracts: ‘contracts for difference’ (CfDs). The notion of CfD used in the text of the regulation, however, differs from the standard one. The latter goes as follows: instead of specifying an actual electricity delivery, a CfD sets a contract price and a nominal quantity that forms the basis for pure monetary transfers between contract signatories. Any quantity injected into the grid by a producer is remunerated at the market price; similarly, the buyer on the other side of the contract pays the market price if he or she decides to consume. Thus, as is the case of spot markets, there is no obligation to inject or withdraw a specific quantity, including the nominal quantity specified in the CfD.
In a standard CfD, the nominal volume only serves as the basis by which to compute financial transfer in a mutual insurance contract. The seller receives a payment from the buyer that is equal to the difference between the contract price and the market price, if the latter is smaller, multiplied by the contracted volume. Symmetrically, the buyer receives from the seller a unit payment equal to the difference between the realised market price and the contract price on this volume, if the latter is smaller. So, if the volumes actually injected and withdrawn correspond to the volume specified in the contract, both sides are fully protected from price risk. Furthermore, as actual wholesale market transactions are totally disconnected from the CfD, they are efficient: the seller puts the quantity of electricity on the market that is profitable at the market price, and symmetrically, the buyer consumes if and only if their willingness to pay exceeds the market price.
Besides providing insurance to the two parties (a perfect one if their supply and demand are known in advance), like PPAs, CfDs weaken the market power of large operators: any profit from an increase in the spot price is offset by a payment from the producer to its counterpart in magnitude equal to the CfD volume.
As announced, though, the notion of CfD in the EU reform differs from the standard CfD contract: the insurance component is triggered by physical delivery. For this reason, we call ‘c-CfD’ the EU version of the CfD, where the ‘c’ refers to the conditionality of the agreement, which is applied only if physical delivery occurs. 1 This mix of financial and physical features fails to disconnect the insurance and the dispatching sections of the agreement and is an inferior design.
The contemplated version of a c-CfD involves the government as the buyer of electricity. In such a c-CfD, the government compensates the producer for lost revenue when the market price is lower than the strike price (the producer’s remuneration is fixed in advance by a reference price known as the ‘strike price’). Conversely, the producer pays the difference when the market price is higher than the strike price. So far, so good. Unfortunately, and in contrast to an ordinary CfD, these monetary transfers only occur if the producer actually puts the corresponding volume on the market.
While c-CfDs reduce the risk faced by investors in new electricity plants without jeopardising the existence of the wholesale market, the fact that the producer’s remuneration is contingent on delivery implies that power plants could be called upon to produce, even though they are not the cheapest. Conversely, electricity may not be dispatched as the production cost lies below the market price. To illustrate this, suppose an electricity producer signs a c-CfD with the state at a strike price of €60 per MWh. If the market price is €40 per MWh, the state will pay the difference of €20 per MWh. If it rises to €80, the producer will have to pay back €20 per MWh. As a result, the producer earns €60 per delivered MWh, regardless of the realised wholesale market price. It is, therefore, in its interest to produce electricity if the strike price exceeds its production cost. If this occurs, it will bid the lowest possible price in order to be certain of being called into dispatching (which is built by stacking production bids in ascending order).
If the market price is €40 per MWh, a plant with a production cost of €50 per MWh should not operate if efficiency is to be achieved. Yet, when the c-CfD strike price is €60 per MWh, it bids below €40, is called in on merit, and pockets a margin of €60-50 = €10 per MWh. Symmetrically, if its production cost is higher than the strike price, it would lose out on every MWh produced. Therefore, it bids an amount high enough not to be called. If its cost is €70 per MWh, it does not produce so as to avoid making a loss, even if the market price rises to €80 per MWh. The conditionality of the insurance contract on actual delivery thus creates an artificial wedge between market price and plant revenue from generation and leads to inefficient dispatching. In this respect, by fully insuring the producer against price variations, a c-CfD functions like another form of conditional contract; that is, the guaranteed feed-in tariffs for renewable energies. These tariffs have contributed to the occurrence of episodes of zero or even negative prices. Indeed, in the case of feed-in tariffs, producers have continued producing in periods of electricity glut, as they receive a relatively high price for electricity that is useless or even detrimental.
Overall, well-designed long-term contracts are good instruments for attracting investment in new generation, preserving the price signal in the wholesale market for efficient dispatching, and sharing macroeconomic risks. However, public authorities should be cautious not to impose distortionary templates on contracts.
Source : VOXeu
