On October 17, the Council of the European Union passed a text reforming the electricity market and favoring long-term contracts to support the energy transition. The design of these contracts should aim at reassuring investors while preserving the efficiency of the wholesale market.
Why reform the electricity market?
The agreement on electricity market reform reached on October 17 by European energy ministers brings to an end a public consultation launched by EU member states and prompted by the 2022 energy crisis. The aim of the agreement is to organize exchanges among electricity producers, retail suppliers and industrial users. It is designed to meet two challenges. The first one is to promote investment in low-carbon power generation equipment. The needs are tremendous, and the remuneration system needs to reassure investors that new wind, solar or nuclear power plants will be financially viable. Such investment is jeopardized in particular by the lack of long-term visibility on green policies and by the long tradition of underpricing of carbon emissions, hence the search of a solution in the form of long-term green supply agreements. The second challenge is to ensure that the installed plants are used efficiently. On the supply side, the cheapest sources of electricity production should be called upon first. On the demand side, the most productive uses of electricity must have priority. Dispatching according to the merit order in the wholesale market meets the second challenge. The price signal thereby generated measures resource scarcity and leads to allocative efficiency. This organization of the short-term wholesale market was reaffirmed in the compromise signed on October 17.
Addressing the investment challenge through long-term contracts
The economics literature distinguishes between two types of long-term contracts: Purchasing Power Agreements (PPAs) and Contracts for Difference (CfDs). PPAs, also referred to as physical contracts, take place outside the wholesale market and are over-the-counter delivery deals between a generator and either an industrial user or a retail electricity supplier. Electricity buyers and sellers agree in advance on the price and quantity to be delivered, and they must acquire the necessary transmission rights from the grid in order to channel the electricity between the point of injection and the point of withdrawal.
In contrast, a CfD does not specify any real electricity delivery, and just sets a nominal quantity that will form the basis for pure monetary transfers. Any electricity placed on the market by a producer is remunerated at the market price; similarly, a buyer on the other side of the contract pays the market price if he or she decides to consume. But there is no obligation to inject or withdraw the quantity specified in the CfD contract. The nominal volume is only the basis to compute financial transfers: the contract is a mutual insurance or financial contract. The seller receives from the buyer a payment equal to the difference (on this volume) between the contract price and the market price if the latter is smaller. Symmetrically, the buyer receives from the seller a payment equal to the difference between the market price and the contract price on this volume if the latter is smaller. So, if for example the volumes actually injected and withdrawn correspond to the volumes specified in the contract, both sides are fully protected from price risk. Furthermore, as actual market transactions are totally disconnected from the CfD contract, they are efficient (the seller puts on the market electricity that is profitable to produce at the market price, and symmetrically for the buyer).
Ideally the volume specified in a CfD contract should correspond roughly to the production volume that is contemplated for the plant. This has two benefits. First, the producer is insured on average; it is not fully insured as adaptation to market conditions is desirable. Second, such forward sales curb market power, if any. Withdrawing electricity capacity from the market raises prices in the wholesale market, especially in periods of scarcity, where the supply response is weak. But if most of the electricity is the object of CfDs, raising the price is not very profitable even for a dominant electricity producer since the price increase will be compensated by a payment from the producer to its counterparty in equal magnitude for the CfD volume.
In fact, the CfD promoted by the October 17 agreement, concurrently with PPAs, differs from the standard CfD of the economics literature. It resembles a CfD except that the insurance component is triggered by physical delivery. For this reason, we will call “c-CfD” the EU version of the CfD, where the “c” refers to the conditionality of the agreement, that is applied only if physical delivery occurs. As we will note, this mix of financial and physical features is an inferior design as it fails to disconnect the insurance and the dispatching part of the agreement. The producer's remuneration is fixed in advance by a reference price known as the "strike price". The contemplated version of c-CfD involves the government as the buyer of electricity. It compensates the producer for lost revenue when the market price is lower than the strike price; conversely, the producer pays the government the difference between the market price and the strike price when this difference is positive. However, these transfers occur only if the producer actually puts the corresponding volume on the market. Let us see what this implies.
c-CfDs reduce the risk faced by investors in new electricity plants without jeopardizing the existence of the wholesale market. Nevertheless, as the producer’s remuneration is contingent on delivery, there is no guarantee that the market’s allocative efficiency will be preserved. Some power plants could be called upon to produce even though they are not the cheapest, and conversely, electricity may not be dispatched, whose production cost lies below the market price. To illustrate this, suppose an electricity producer signs a c-CfD with a strike price of 60 euros per MWh. If the market price is 40 euros per MWh, the State will pay the difference of 20 euros per MWh. If it rises to 80 euros, the producer will have to pay back 20 euros per MWh. As a result, the producer earns 60 euros per MWh regardless of realized wholesale market prices. It is therefore in its interest to produce if the strike price exceeds its production cost (if so, it will bid the lowest possible price to be sure of being called into the dispatching, which is built by stacking production bids in ascending order of bidding).
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 CfD strike price is €60 per MWh, it bids below €40 and is called in on merit and pocket 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. It therefore bids an amount high enough not to be called. If its cost is €70 per MWh, it does not produce in order 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 exploitation, and leads to inefficient dispatching. In this respect, by fully insuring the producer against price variations, a c-CfD works like the guaranteed feed-in tariffs for renewable energies, which have contributed to the occurrence of episodes of zero or even negative prices.
The right mix of insurance and incentives
CfDs therefore need to be carefully designed. The aim is to provide guarantees on future remuneration that will encourage investment (new generation capacity and maintenance of existing capacity) while preserving the efficient dispatching properties of the wholesale market. As the text of the agreement states, "The design of these two-way contracts for differences should preserve the incentives for the generating facility to operate and participate efficiently in the electricity markets, in particular to reflect market circumstances." The EU c-CfDs do not. Generators should not be obliged to bid on the wholesale market to benefit from insurance.
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The reform of the electricity market, originally intended to address the energy crisis, will determine to what extent the goal of carbon neutrality by 2050 can be achieved, and at what cost. As we explain at greater length in a note that can be downloaded here, long-term contracts should be part of the solution, provided they are well designed and the wholesale market is preserved. The retail market also needs to be rethought to adapt to new uses (self-consumption, electric mobility, energy storage, etc.). The October 17 agreement is strangely silent on this subject. It merely recommends that, in the event of another sustained price surge such as the one seen in 2022, governments should be able to easily adopt "tariff shield" type measures as part of a crisis mechanism.
The fight against global warming, geopolitical tensions, the social acceptability of generation technologies, and technological uncertainty all create major macroeconomic risks. Ultimately, someone has to bear these risks, a fact that many people shut their eyes to. Long-term contracts are the ideal instrument for sharing these macroeconomic risks. The State can govern and regulate this insurance market, but it must not rigidify its terms and conditions, for example by placing all electricity production under a single-price c-CfD, which could kill off the market and prevent both optimal risk-sharing and efficient dispatching.
Published in La Tribune
Graph source: https://www.epexspot.com/en
