This blogpost from Dr. Bert Willems is an edited and commented excerpt from CERRE’s December 2022 report “Recommendations for a Future-Proof Electricity Market Design”, by Prof. Michael Pollitt (University of Cambridge), Prof. Nils-Henrik von der Fehr (University of Oslo), Dr. Bert Willems (Tilburg University), Prof. Catherine Banet (University of Oslo) and Prof. Chloé Le Coq (University Paris-Panthéon-Assas, Stockholm School of Economics), and external contributors Prof. Anna Rita Bennato (Loughborough University) and Daniel Navia (University of Cambridge). For more, check out the report on our website.
The European Commission recently closed its public consultation on the reform of the EU’s electricity market design and is expected to table a proposal on March 16. In the version of the proposal that leaked this week, the Commission is taking measures to improve the PPA (Power Purchasing Agreement) and forward markets. Member States can make use of ‘hybrid’ market design to support new RES investments, but the Commission puts some requirement in place to protect the functioning of the spot market and preventing crowding-out of PPA markets: Support contracts need to be equivalent to two-way CfDs, which are more financial and keep short-term incentives intact, and governments should prioritise allocating CfDs to investors that have PPA contracts in place. The proposal leaves many design details unanswered and might not go far enough for some stakeholders who favour managed CfDs for all generation assets.
The fact that the European Commission did not originally consult on a well-defined set of measures for long-term contracts but instead considered a wide range of options, reflects the fact that there are major differences of opinion between member states. This is no surprise, as there already exists large national differences in the implementation of short-term markets, the role of capacity markets, the support schemes of RES, and regulation of the retail tariffs. Some fundamentals must be kept in mind when considering such schemes and as the final version of the Commision’s proposal will soon be published and discussed at the Council and the European Parliament.
Improving the market for long-term contracts
We expect the use of long-term contracts by private parties will increase in the long run net zero scenario. Price volatility is expected to increase, government price guarantees for RES such as feed-in tariffs, will phase out, and the prudential regulation of the retailers will become stricter (CERRE, 2022, p.28).
We also expect innovation in energy contracts. Long-term contracts will need to go beyond standard forward contracts on the day-ahead market. Specific contracts, such as Power Purchasing Agreements (PPAs) are needed to target actors with different risk profiles (retailers, intermittent RES producers, storage operators, aggregators, conventional generators). Balancing contracting positions might require multilateral contracting (CERRE, 2022, p.96). For instance, a wind farm, a retailer, and a storage operator together might have a lower risk exposure than any two players together.
The market for corporate PPA is likely to mature further, but integrated companies with portfolio investments will remain important as well. Those could be in the form of classical utilities, but also in special purpose vehicles such as energy communities or integrated offshore energy hubs. Those structures can prevent hold-up in closely intertwined investments.
Government intervention in long-term markets
There are good arguments for government intervention in the contracting market such as: regulating the risk of retailers, standardising contracts to simplify netting of positions, improving transparency, contracting on behalf of consumers to prevent future intervention by the government, and providing natural counterparties for some contracts. The lastcategory should cover activities that are heavily affected by regulation, such as the availability of transmission capacity and long-term carbon policies with long-term transmission rights and options on the CO2 ETS price. However, a key role remains with private parties.
The existing market has worked well in providing consumers with the option to lock-in prices three to sometimes five years in the future, but consumer demand for those contracts was often limited. While producers might like longer-term contracts to reduce their capital costs, economists disagree on whether and how we should regulate hedging beyond this period, especially given the lack of consumer demand for longer term hedging. Some economists argue for more government intervention in the long-term contracting market and structural market design changes, in what is called a hybrid market design (See CERRE, 2022, p.101)
We believe that the subsidiarity principle should apply with respect to the implementation of organised long-term markets for two reasons: There is no consensus among economists or industry participants on whether we need a large market reform based on long-term contracts. Member states also have different social contracts regarding the role of governments in steering markets, and their consumers have different risk-appetites across.
There are benefits from using organised long-term markets as they will lower capital costs for investors and hedge consumers against large price changes.
Government intervention for long-term contracts may make more sense for base-load producers (e.g., nuclear, and renewable energy suppliers) as they have large investment costs, and are less likely to be price setters, and therefore have higher risk exposure if private contracts do not provide sufficient hedging. For gas-fired power plants, the electricity price follows their input cost as they are often marginal, and their price risk is therefore lower.
Flexible energy sources such as storage and demand side management might find it hard to find long-term hedging contracts in organised futures market, but it is not obvious that targeted government-mandated contracts will be useful here. Governments might find it hard to quantify the portfolio benefits of different flexibility technologies and bilateral private contracts are likely to be more innovative than standardised government contracts. Moreover, portfolio investors might build a mix of renewable energy and storage facilities and internalise risk offsets within a company (ibid., p.97).
Many countries in Europe already have a form of hybrid markets as they are using distinctive styles of support schemes for renewable energy and capacity markets, next to a more harmonised wholesale market. Harmonisation at EU-level might help improving the efficiency of those schemes for renewable energy, capacity markets and potentially long-term contracts and allow for international trade. So, there is no need for a revolutionary new design to improve the role of long-term contracts.
Drawbacks of government-backed contracts
However, there are also drawbacks of government-backed long-term contracts, which might have implications for the internal market, and for which the European Commission might impose some minimal requirements at the central level:
- The contracted capacity might not fully take part in the short-term markets: day-ahead, balancing, and ancillary service market. This could reduce production efficiency and reduce spot market liquidity.
- There might be too little competition for long-term contracts, with insufficient cross-border participation as long-term transmission contracts do not exist and contracts are not sufficiently standardised between Member States.
- format might suit one technology more than another. So, we might obtain an inefficient combination of production technologies. This might be in particularly valid for demand response, storage, and other forms of flexibility.
- Government-regulated contracts might crowd-out private PPAs and portfolio investments because the government could offer better contracting conditions and does not price the risk of different assets correctly.
- Energy prices might be too low, if a government exercises its monopsony power as a single buyer and extracts resource scarcity rents by signing long-term contracts at below the expected market rates and passes the lower contract price on to consumers. This could be a form of state-aid (ibid., p.98)
Empirical evidence on long-term contracts highlights some of those pitfalls. Chattopadhyay & Suski, (2022) indicate that legacy long-term PPA contracts slow down innovation, reduce spot market liquidity and are often less competitive with higher prices. In CAISO and MISO, regulated planning processes, utility programs, and state-directed procurements for preferred resource types several years in advance have crowded out short-term capacity markets. Capacity markets were therefore not successful in attracting merchant investments and large quantities of low-cost capacity supply (Pfeifenberger et al. 2017). In the Ontario market, the operational decisions of some assets (renewable, hydroelectric, and nuclear) do not respond to market prices, because they are subject to fixed price contracts independent on production levels (Pfeifenberger et al. 2017). The Colombian contract model did not provide enough incentives for intermittent RES (Olaya et al., 2016). However, there are also many examples where government-mandated targeted long-term contracts have accelerated investments. For instance, in the UK, the Low Carbon Contracts Company has contract about 30GW of new capacity under Contract for Differences (CfDs).
How to minimise these drawbacks?
The European Union might try tolimit the downsides of those effects by providing some guidelines on contract design, but those often increase the risk for investors as well. Examples of such measures are as follows:
- Make the contracts technology neutral and standardised to increase the number of bidders. Contracts could focus on hedging long-term price exposure of consumers, and less on the hedging needs of producers.
- Use an auction to determine the contract price, as this will create more competitive pressure.
- Allow portfolios of technologies to participate in the market for government contracts. For instance, a RES producer combined with a storage operator can sell a forward contract and manage risk internally. This reduces the need for the auctioneer to rely on availability and portfolio risk factors in the auctioning process or will allow at least some arbitrage between technology choices. This will require, however, more financial monitoring on the risk exposure of portfolio bidders.
- Allow contracts to be traded on secondary markets, so firms can reallocate contracts. This will allow inefficient generation capacity to exit the market, and retailers can adjust their contracting positions if they gain or lose customers. Secondary markets are important for firms to mothball technology in a timely fashion. To enable secondary markets, contracts should not be strictly bound to a particular asset. For instance, if an inefficient asset is under a long-term contract with historical favourable contracting conditions, it might not be in the firm’s best interest to mothball the asset, unless the contractual obligations can be transferred to other assets.
- Turn physical contracts into financial contracts, such a Contract for Differences, where contract deviations are settled financially. This keeps incentives for availability and participation in the spot market. It requires liquid short-term markets to function well.
- Fix the contracted quantity ex-ante. Contracts should be based on deemed capacity and not available capacity. Take-or-pay clauses that are sometimes used for thermal generators eliminate their incentive to participate in spot markets and reduce liquidity. This is also the case for renewable energy production. Hence, the risk for unavailability must be with the seller of the contract.
- If resource scarcity rents are extracted, this should happen in a transparent way, and state aid concerns need to be addressed, when rents are reallocated.
- Allow cross-border participation in the auctions for long-term contracts, as this will increase competition. This will require long-term contracts for transmission capacity (CERRE, 2022, p.99-100).
Conclusion
The energy crisis has stirred up a discussion on whether (long-run) risks and incentives are correctly allocated between investors, consumers, utilities, and the government; especially considering a future net zero energy system. The lack of long-term contracts has exposed consumers to price spikes and created windfall profits for inframarginal production. Do Member States need more tools to promote long-term contracts in a so-called hybrid system?
Many Member States already supplement the short-term market with additional mechanisms, for instance to support renewable energy and nuclear, and capacity renumeration schemes. State-aid rules have explicit provisions for those contracts. Hence, Europe already has hybrid markets.
The current discussion allows the Commission to ascertain whether those hybrid markets need to become more harmonised to improve competition and prevent a fragmentation of the European energy market, and whether state-aid rules should be adapted to allow governments to intervene more explicitly in risk allocation and to prevent distortions of short-term markets. The precise design principles of the CfDs support program will determine whether they are beneficial for the energy market.
The crisis also shows that we need to step up the regulation and monitoring of risk in the energy sector. This takes many forms: energy procurement by individual retailers, margin requirements for financial contracts, the use of physical and financial collaterals, netting of contracts, the allocation of congestion risks, monitoring the liquidity and pricing of futures markets, and assessing systemic risks.
Since its inception, the European internal power market has been evolving continuously, and it will continue to do so. We have established a well-functioning set of short-term markets, cherished by most stakeholders. This has resulted in a European-wide well-integrated internal market, which benefited security of supply and competitiveness. We do not need a revolutionary new European-wide market design, but an improved regulatory framework for hybrid markets which Member States can apply based on national preferences, and better monitoring and regulation of risk.
